Offshore Update 1-2012 by DNV GL (old account)

Low risks in the high north?

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offshore update

News from DNV to the offshore industry

No 01 2012

Photo: xx

Forensic investigation

contents

04 Forensic investigation

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11 Low risks in the high north?

Forensic engineering and failure investigations enhance safe operation and preserve assets........................... 4 Low risks in the high north?.......................................................... 11 Standardising Arctic challenges................................................ 14 Subsea 7 Buoyancy Supported Risers for Petrobras............ 18 Take control from well to terminal with SilverPipe..... 22 Introducing the ship of the year – the North Sea Giant..........................................................................24 Software standard gains momentum with new drilling rigs................................................................................... 28 A plug-in solution................................................................................. 30 New DNV drive results in updated rule book for self-elevating units.................................................................... 32 Barrier management for offshore safety............................... 34 Taking deepwater pipelines to the X-Stream.......................... 36 Energy efFIciency for OSVs4�� 40 Barents 2020 conclusive summary................................................. 44 Wellstream awarded DNV’s local content certiFIcation for Brazilian operations4�� 46 Deepwater drives the development of new technology.................................................................................... 48 West African Gas Pipeline................................................................... 49 Mooring systems in deepwater FIelds5�� 50 Hushing underwater noise.............................................................. 54 Maintenance of mobile offshore units and floating structures – it’s only getting better......... 56 DNV Houston shows software integrity.................................. 58 Synergi looks to Asia and the Americas.................................... 60 Pertamina: going for “world class” by 2014............................. 62 Observations of onshore pipeline regulatory trends... 64 Oil spill risk management................................................................. 66 Making SEMS – enhancing offshore safety in North America................................................................................... 68 DNV acquires Vattenfall shares in STRI.................................... 70

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36 X-Stream

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offshore update Published by DNV Maritime and Oil & Gas, Market Communications Editorial committee: Blaine Collins, Director, Divisional Staff, Division Americas Magne A. Røe, Editor Lisbeth Aamodt, Production Design and layout: CoorMedia.com 1204-019 Front cover: Ship of the year – North Sea Giant. See page 24 Photo: North Sea Shipping Please direct any enquiries to DNVUpdates@dnv.com Online edition of offshore update: www.dnv.com/offshoreupdate DNV (Det Norske Veritas AS) NO-1322 Høvik, Norway Tel: +47 67 57 99 00 © Det Norske Veritas AS www.dnv.com

eDitOrial

rethiNkiNg risk MaNageMeNt FOr OFFshOre saFety

elisabeth h. tørstad chief operating officer, Division americas elisabeth.torstad@dnv.com

Photo: stockbyte/getty images

we have been reminded several times over the last few years that major accidents happen and that external events can have a significant impact on our lives, our industry and our business. the question is not whether we are exposed to risks and uncertainty, but how we can manage them, and how we can maximise our opportunities and rewards

while minimising our exposure. managing risk is now a buzzword, and boards and managers everywhere are looking for effective risk management solutions. risk management should be an integral part of an organisation, something that influences behaviours and decisions every day. and the efficiency of risk management methods should be measured by well-defined parameters to enable us to learn what is working and stop what does not lead to improvements. both the offshore oil and gas industry and maritime industry have demonstrated significant improvements in occupational safety, safe and healthy working conditions for men and women, over the last decade. that job will never end but, overall, we can say that occupational safety is

improving and that current best practices are effective. attention to major accidents, such as the prevention of fires, explosions, navigational errors, collisions and similar accidents, is a different story. the earlier risk management thinking was that reducing the frequency of accidents would lead to a positive correlation to a reduction in the more severe accidents. however, we have no indications that this has happened. managing risk is the core of dnv’s business and we are continuously working to stay at the forefront of the development of methodology and practices, in order to be even more effective in preventing accidents and mitigating their consequences. today, barrier management has been identified as an effective way of pre-

venting major accidents. the methodology considers scenarios and threats that may lead to major accidents. then, for each threat, barriers – technical, physical, operational procedures, management and decision making – are developed and implanted to remove the threat, prevent it from occurring or mitigate its consequences. barrier management is also well-suited for managing both the immediate, or short-term, and longterm consequences of an accident. indeed, barriers have critical functions to safeguard life, property and the environment. however, analyses of most major accidents show that barriers have been in place but that the failure of these barriers has led to accidents or failed to control the consequences. why? barriers are not typically moni-

tored during operations, operators are not aware of the significance of barriers or decisions are made without regard to barrier status. barrier management includes addressing the deterioration of a barrier over time, usually in operating practices, and a rapid response in order to maintain barriers, including decisions to shut down if a barrier is not functioning. as we move forward, let’s remember that a key element of successful risk management is monitoring changing threat and hazard conditions, especially the status of the barrier designed to control them to prevent accidents. the risk picture in our industry continues to increase in complexity and we need to take a giant leap, make a big step change, in how we manage process risk.

THE POWER TO LEAD oFFshore uPDate NO. 1 2012 |

Forensic engineering and failure investigations

Forensic engineering and failure investigations enhance safe operation and preserve assets Forensic engineering is the investigation of materials, products, structures or components that fail or do not operate or function as intended, causing personal injury, damage to property or the environment, or a loss of productivity. TEXT: NEIL G. THOMPSON, DNV

Forensic and failure investigations also deal with retracing processes and procedures leading up to accidents involving the operation of vehicles, equipment, machinery and other assets. The term forensics is applied most commonly in legal cases, although the same cause analyses apply more generally to failure investigations. The purpose of a forensic engineering investigation is to determine the cause or causes of failure (1) with a view to improving the performance or life of a component, (2) to prevent a similar failure and promote lessons learned and safe operating practices, or (3) to establish the root cause of the failure. The following are important in the field of forensic engineering: (1) the process of investigating and collecting data related to the materials, products, structures or components that failed and (2) the documentation of the records, evidence and documents received. This involves inspections, collecting evidence, measurements, developing models, obtaining exemplar products and conducting tests and simulations. The DNV team DNV is one of the few firms to combine engineering with stateof-the art research and testing (Figure 1). DNV maintains four primary laboratory facilities throughout the world to serve the needs of its customers. These are located

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in Høvik and Bergen in Norway, in Dublin, Ohio, USA, and in Singapore. DNV’s researchers and scientists at these facilities work closely with the DNV engineering staff to provide customers with engineering solutions based on fundamental science, as well as testing solutions balanced by sound engineering practice. DNV has laboratory and engineering expertise in the fields of mechanical, structural, materials, corrosion, chemical and metallurgical engineering. The company serves the oil and gas, maritime, power utility, alternative cleaner energy production, onshore and offshore pipeline, refinery and deepwater applications industries. DNV’s renowned scientists have extensive experience in designing laboratory tests and selecting critical variables that permit the accurate simulation of field conditions. DNV’s staff not only stay on the cutting edge of the latest practices and technologies, but in many cases also drive cutting-edge practices through their multitude of testing activities, research programmes and joint industry programmes. DNV has the ability to conduct component testing that utilises state-of-the-art analytical techniques, including laser scanning; scanning electron, optical and threedimensional microscopy; energy dispersive,

x-ray and Ramon spectroscopy; and many others. Testing and research includes: ■■ Technology qualification ■■ Full-scale testing of components and systems ■■ Process simulations ■■ Process development and changes ■■ Materials selection ■■ Chemical treatment needs ■■ Corrosion mitigation and monitoring ■■ Coating specifications and selection ■■ Elastomer selection ■■ Fracture mechanics and fatigue ■■ Multiphase flow testing DNV’s ability to perform model simulations is critical to many forensic and failure investigations. These include finite element (or boundary condition) analysis for mechanical, structural, thermal, corrosion and cathodic protection, soil movement, and flow model simulations. Specialised models have been developed for corrosion damage growth predictions, creep life predictions, predictions of critical pressure for failure of pressure vessels, etc. DNV performs failure and forensic investigations worldwide, using its diverse laboratory network and over 300 offices in 100 countries. DNV has a staff of more than 9,000, a high percentage of whom are scientists, researchers and engineers.

Forensic engineering and failure investigations

of assets. However, when failures occur, DNV is there to support its clients with a range of services – we are globally renowned for this. Our experts apply our knowledge of industry practices gained by years of working closely with operators recognised for ‘doing it right’ (and learning from those who don’t). Our approach is augmented by an in-depth knowledge and understanding of relevant codes and regulations. DNV’s incident response services include: ■■ 24-hour hotline/response team [855-DNVCALL (368–2255)] (United States) ■■ First responder consultation ■■ Onsite/in-the-ditch failure investigation

Evidence retention and preservation Chain of custody ■■ Forensic engineering/science ■■ Testing and research laboratories ■■ Corrective action response ■■ Component failure analysis ■■ Component and process simulations and modelling ■■ Incident root cause analysis ■■ Review of technical data (maintenance, inspections, construction records, etc.) ■■ Review of documentation (integrity and corrosion management protocols, regulations, etc.) ■■ Formulation of defence strategies ■■ Regulatory support ■■ Expert consultant or witness ■■ ■■

Photo: DNV

Knowledge and experience count What makes DNV unique is its approach to forensic and failure investigations. DNV maintains a staff of Ph.D. research scientists and integrity engineers who are globally recognised for their expertise in structural integrity (pipeline integrity management and the mechanical integrity of facilities) and root cause analysis. DNV offers not only a complete understanding of operations, maintenance, engineering, codes and regulations for a wide range of industries, but a knowledge of the mechanisms that lead to failure (Figure 2). DNV’s primary business is preventing failures and ensuring safe operation

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Figure 1: Strain testing.

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Photo: DNV

Forensic engineering and failure investigations

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Figure 2: Pipeline failure inspection.

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Forensic engineering and failure investigations

Personnel

Methods

Equipment operations

training

inspections

errors

valves

Strategy and Policy

welding

procedures

management

Continual Improvement

pumps

Management Review

Accident welds alloys steels Materials

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CP NDE pressure

Measurements

product

Planning

soil

Monitoring and measurement

temperature

Implementation and operation

Environment

Figure 3: A “cause-and-effect”, or Ishikawa, diagram.

Root cause analysis Forensic and failure analyses can take many forms and levels of activities. Many failure investigations focus on the immediate failure cause; i.e., for metals, the metallurgical or technical aspects of the failure. Laboratory tests are performed to determine whether or not a material meets the applicable mechanical and chemical specifications. Metallurgical analyses are performed to determine whether the failure was associated with an overload, fatigue vibrations, corrosion, or any of a number of other causes. Going further, basic causes such as operational issues can be examined, e.g., a review of the technical literature, such as corrosion and integrity management protocols, is performed to determine what aspects of the operations and maintenance contributed to the failure. A true “root cause” analysis takes the investigation one step further. The root cause analysis considers the management decisions that were made, or not made, and that contributed to the failure. By tracing the cause of the failure back to failures of management systems or processes, it becomes more likely that similar failures will be prevented from occurring in the future. This improves performance by avoiding lost production time and repair or clean-up costs, provides a safer

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Figure 4: Continuous improvement loop.

environment for employees and the public (for assets such as pipelines), and prevents costly environmental damage (for assets dealing with hazardous liquid and gases). A good root cause analysis is dependent on a complete and accurate basic and intermediate cause analysis. Understanding the chain of technical events and management decisions leading up to a failure allows one to “reverse engineer” and reconsider decisions and operational processes. Ideally this leads to recommendations that are implemented by management. There are many tools that can be used to assist in the root cause investigation. Some of these tools are commonly used project or programme management techniques. Some of the tools are highly specialised, and designed to focus specifically on root cause analysis and failure investigations. General tools include various statistical analysis techniques, charts and diagrams. Most engineers and managers are familiar with histograms, scatter charts, tree diagrams and fault tree analyses. Many are familiar with “cause-and-effect” diagrams (also known as “fishbone” or “Ishikawa” diagrams), which can be invaluable in clarifying the different components or processes that may have contributed to a

failure. An example is given in Figure 3. The best root cause analysis tools force one to consider aspects of the failure that may not be obvious to the casual observer. DNV has developed an approach that is specifically designed to perform root cause analysis. This approach is the Systematic Causation Analysis Technique (SCAT), which is a structured application of the Loss Causation Model (LCM). The LCM is based on the concept that a loss of management control can ultimately lead to an accident/failure. The loss of control leads to a basic cause of a failure, which leads to an immediate cause of a failure. By tracing the appropriate chain of events, one can identify and correct the loss of control that contributed to a given failure. The SCAT approach begins with a collection of all the available evidence. This will include the findings of the failure analysis, as well as interviews with key personnel involved in the incident and a review of the applicable documentation. The evidence is used to develop a timeline of the events that led to the failure. Key events may include: lack of inspection, inadequate response to inspections, lack of control of operating parameters, operating outside of the design envelope, etc. Most industrial accidents/failures can be attributed to a chain of events. It is important

offshore UPDATE NO. 1 2012 |

Forensic engineering and failure investigations

to understand how and why each event occurred and how it led to the next event in the chain. Following the development of a timeline of key events is an analysis of barriers. Barriers are any components or systems that are put in place to prevent failures. Physical barriers include pressure and temperature control systems and other similar barriers. More “abstract” barriers to consider are the training of personnel, communication procedures and quality assurance protocols. It is the failure of these barriers that leads to the events that make up the chain preceding the failure. Each one of the events in the chain must be analysed separately to understand how and why the barriers in place to prevent them failed. For each one of the events, one must consider the immediate, basic and management control contributions. The failure only occurred because all of the barriers failed. Once the analysis has identified the true root cause of the failure, it becomes possible to make recommendations to prevent future failures. As most failures are the result of the failure of several barriers or several human errors, it is likely that several corrections could be implemented into the operational procedures or management systems to correct the root cause. This may include the re-training of staff or additional review of designs and procedures. New safety systems or operational processes can be implemented as necessary. The prevention of future failures is the real value of a root cause analysis. Lessons learned DNV has the ability to follow up its forensic investigations with operational and management reviews to implement the lessons learned. DNV has developed the International Safety Rating System 8th Edition (ISRS8) as an accumulation of best practice experience in safety and sustainability management. ISRS8 has been developed over 30 years and is regularly updated to reflect changes and improvements in safety management. The 8th edition of ISRS was issued in 2009 and

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includes elements of process safety management as well as updates to reflect the changes in international standards such as OHSAS 18001:2007, ISO 9001:2008 and the Global Reporting Initiative 2006. ISRS8 is designed to ensure the health of industrial processes, drive continuous improvement and ensure effective risk management. ISRS8 takes strategy and policy, planning, implementation and operation, monitoring and measurement, management review, and continual improvement and combines these efforts into one procedure that can be used to manage any industrial process. A visual representation of the ISRS process is shown in Figure 4. CASE STUDY – BLOWOUT PREVENTER FROM THE DEEPWATER HORIZON DISASTER On the evening of 20 April 2010, while drilling at the Macondo Prospect, control of the well was lost, allowing hydrocarbons to enter the drilling riser and reach the Deepwater Horizon, resulting in explosions and subsequent fires. The fires continued to burn for approximately 36 hours. The rig sank on 22 April 2010. From shortly before the explosions until 20 May 2010, when all ROV intervention ceased, several efforts were made to seal the well. The well was permanently plugged with cement on 19 September 2010. A Joint Investigation Team (JIT) consisting of members of the Departments of the Interior (DOI) and Homeland Security (DHS) was charged with investigating the explosion, loss of life and blowout associated with the Deepwater Horizon drilling rig failure. As part of this overall investigation, DNV was retained to undertake a forensic evaluation of the blowout preventer (BOP) stack, its components and associated equipment used by the Deepwater Horizon drilling operation. In the event of a loss of well control, various components of the BOP stack function in an attempt to seal the well and contain the blowout. The most important of these components is the blind shear ram (BSR). The focus of the forensic

investigation was on determining the cause of the failure of the BSR to cut the pipe and seal the well. DNV was uniquely positioned to assemble a team of experts with all the necessary competencies to complete the project; including expertise in large project forensic investigations, deep water drilling, BOP operation and design, materials science, mechanical engineering, electronic systems, laboratory testing, and structural and mechanical system modelling. The DNV team was led by the Dublin, Ohio Materials and Corrosion Technology Centre, with staffing support from the Dublin, Ohio’s asset risk management group, DNV’s Houston’s energy solutions group and product verification and inspection group, and DNV Høvik, Norway’s energy solutions group. The visibility of this forensic investigation was understandably high. Throughout the investigation, several US federal agencies were involved and had representatives on site; including the Bureau of Ocean Energy Management Regulation and Enforcement (BOEMRE), US Coast Guard, NASA, Federal Bureau of Investigation, Environmental Protection Agency, Department of Justice, Department of the Interior and Chemical Safety Board. In addition, a technical working group (advisory capacity only) consisting of technical representatives of other interested parties was established and legal representatives of interested parties were permitted on site. All the parties were present to observe or advise, but all final decisions were made by the DNV team and approved by the JIT. The investigation was conducted in a US Coast Guard dock on the NASA Michoud Facility in New Orleans, LA and at other facilities on the NASA base. As an indication of the project size, 400 persons signed non-disclosure agreements as a part of this project over the 13-month duration. Using a fault tree analysis and SCAT timeline to narrow the possibilities, the investigation included the function testing of the hydraulic systems, control systems and individual components of the BOP, including the BSR, casing shear

Forensic engineering and failure investigations

›› Figure 7: Alignment of scanned ram blocks and drill pipe based on the separation predicted by the FEA off-centre shear model; note the significant erosion of ram blocks.

›› Figure 6: Final deformation of the drill pipe as predicted by the off-centre Pipe Model; the edge of the drill pipe nearest the wellbore is trapped between the faces of the ram blocks.

›› Figure 5: Finite element buckling prediction; at the top of the model, the

drill pipe is centre in the upper annular; at the bottom of the model, the drill pipe is centred in the upper VBR.

rams, three variable bore rams (VBR), of which the lower one was configured as a test ram, and annulars on the lower marine riser package (LMRP). The most significant findings involved the drill string pieces removed from the BOP and the riser adjacent to the BOP. As in any investigation, the direction of the investigation must be governed by the evidence available. Although, when the investigation started, many thought that the BSR did not function, the drill pipe and rams told a different story. The investigation indicated that the BSR had functioned, resulting in the pipe being at least partially sheared, but the drill pipe was located off-centre in the wellbore and a portion of the pipe was caught in the faces of the BSR ram blocks outside the cutting surfaces. This prevented the BSR from fully closing and sealing the wellbore and permitted the flow to continue and the subsequent erosion to enlarge the effective flow path area. The position of the drill pipe offcentre in the wellbore was completely unexpected, especially since the pipe was centred above the BSR by the closed upper annular and below by the closed upper VBR. The DNV team suggested that the cause of the off-centre pipe was an elastic buckling mechanism and verified the possibility of this mechanism using finite element modelling (Figure 5). The DNV team also used finite element modelling (Figure 6) to illustrate the consequences of shearing the off-centre drill pipe. Laser scans were performed on all ram and pipe components. Figure 7 shows the BSR ram blocks with the bottom drill pipe at the positions predicted by the finite element model for the shearing of the off-centre pipe. Recommendations were provided in the final report to BOEMRE outlining further testing and industry recommendations. [The full report is available through the BOEMRE website.] As a part of the forensic investigation, senior DNV team leaders gave testimony to the JIT board, depositions to the multidistrict litigation authorities and interviews to the Chemical Safety Board. 

offshore UPDATE NO. 1 2012 |

Arctic operation

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arctic OperatiON

low risks in the high north? major oil and gas accidents in the past few decades have forced significant improvements in technology, procedures and regulations. “now, when seeking opportunities in the arctic areas we must ensure the same level of risk as in the north sea,” emphasises knut Ørbeck-nilssen, Dnv coo Division norway, russia and Finland. teXt: SVEIN INGE LEIrGuLEN, dnv

oil and gas producing countries have experienced several catastrophic accidents in the past 30 years. alexander l. kielland in norway, piper alpha in the uk, montara in australia and deepwater horizon in the us have all claimed many lives or caused significant oil spills. mr Ørbeck-nilssen explains that another common characteristic with all these tragedies is that they were completely unexpected. however, they have forced the development of improved procedures, standards and technologies. on the regulatory side, responsibilities have become clearer and new governmental safety agencies have been established. “offshore safety has never been so high on the public agenda as in the past year. the industry is debating how to improve technologies and safety solutions, and authorities in both the us and the eu are developing stricter requirements for oil and gas operations. there is no doubt that the rules of the game will change with more focus on offshore safety, environmental protection and risk assessments,” he predicts.

Photo: Damir cvetojevic

rISK MaNaGEMENT ENHaNcES SaFETy “the use of a risk management approach is vital to increase safety. we should not confuse the risk of a certain event taking place with only the consequences it may result in. that is not taking into account the likelihood for the event to occur. this approach, the so-called ‘worst case scenario’ will lead to many decisions without a sound factual basis. “this is not what risk is about. risk management is about increasing safety by analyzing what and where something can go wrong, minimising the probability for it to occur and

oFFshore uPDate NO. 1 2012 |

Photo: Damir Cvetojevic

Arctic operation

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As the industry moves north into the Arctic, and seen in the light of risk management, both policy makers and the industry must agree on an acceptable risk level. As a minimum we should maintain the same risk level as in the North Sea,” says Knut Ørbeck-Nilssen, DNV COO Division Norway, Russia and Finland.

ensuring that you can reduce its consequences,” he clarifies. An oil and gas operator who embraces this approach within its management system will be able to enhance and manage safety levels, continuously. Authorities that base their regulations on a risk based approach will also have a pragmatic tool that enables them to decide on an acceptable level of risk for their countries to harvest resources. This also provides the basis for regulations that allow for technology development and new and better solutions. Risk analyses will further provide a common interface for discussions between stakeholders, for example regarding a decision of whether or not to allow an industrial activity.

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“This is indeed how many companies and countries, such as Norway and the UK, have managed their oil and gas operations for many years. Here, both regulations and operations are based on risk management, and the responsibility falls on the operator to obtain a certain safety level,” says Mr Ørbeck-Nilssen. Managing icy risks 20% of the world’s undiscovered resources may be found in the Arctic regions. He points out that exploration has already started in the harsh environments found in Greenland, Shtokman and the Barents Sea, with more to come. “In these locations, achieving safe operations is more demanding than in

for example the North Sea, where oil and gas has been produced since the 1970s in some of the world’s most challenging conditions. In the high north the conditions are much, much tougher. Extremely low temperatures and long periods of darkness create a demanding working environment for personnel, but it also affects the material properties and operation of equipment,” he explains. Snow, slush, fog and icing can reduce the functionality and availability of safety barriers. And closely linked to this is the question of how emergency preparedness and oil spill recovery can be provided in case of an accident. “How do you remove oil from ice, and how do you evacuate 100 people in a

Arctic operation

Major accidents since 1980

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In the high north the conditions are tough. Extremely low temperatures and long periods of darkness create a demanding working environment for personnel, but it also affects the material properties and operation of equipment.

ALEXANDER L. KIELLAND The collapse of the Alexander L. Kielland rig in 1980 is still fresh in the minds of the international oil and gas industry and particularly in the Norwegian community. A bracing on one of the legs broke, probably due to fatigue, and the unit had no redundancy against this eventuality. Shortly after, the leg was lost, causing a rapid list of 30–35 degrees. After twenty minutes the rig turned upside down completely. Nobody had foreseen this accident which caused 121 lives. PIPER ALPHA Eight years later, on the UK continental shelf, 167 lives were lost in the Piper Alpha disaster, making this the worst offshore accident ever experienced. An explosion was caused by gas released and ignited by hot gas turbine casings or frictional sparks.

Photo: Damir Cvetojevic

MONTARA In 2009, an oil and gas leak and subsequent slick took place in the Montara oil field in the Timor Sea, off the northern coast of Western Australia. Lasting for 74 days, it was one of Australia’s worst oil accidents.

–50°C snowstorm 200 km from the shore with limited infrastructure in remote locations?” he asks. “These are just a few examples of the safety challenges we must face in the years to come, but I know that much research and development is already in process,” Mr Ørbeck-Nilssen points out. International cooperation He emphasises another important issue, which is international cooperation. “All five Arctic coastal states must work together to implement the same understanding, standards and regulations with regards to offshore safety. A great example of cooperation is the Barents 2020 project between Russia and Norway. Since 2006,

experts from both countries have worked closely together in order to learn, develop and harmonise rules for safety in the Barents region. This was initially a bilateral initiative, but it is now developing into a significant pan-Arctic project,” he states. Mr Ørbeck-Nilssen believes that as the industry moves north into the Arctic, and seen in the light of risk management, both policy makers and the industry must agree on an acceptable risk level. As a minimum we should maintain the same risk level as in the North Sea. He explains that, since the consequences in these sensitive areas will be much higher in case of an accident, the emphasis must be on developing solutions which reduce the probability of undesired events.

DEEPWATER HORIZON The Deepwater Horizon accident happened on April 20, 2010 when the control of the Macondo well was lost resulting in explosions and fires on the drilling rig. It was the largest oil spill in US history, and in comparison to the Exxon Valdez’ 500,000 barrels spill, the Macondo well released five million barrels into the Gulf of Mexico.

“Further, to minimise the consequences of an accident, the industry and the regulators must work together to find appropriate mitigation measures in order to meet the agreed risk level,” he underlines. “We recommend that the five Arctic states agree on common regulations, and the industry must develop technologies and standards adapted to the harsh Arctic conditions. I see this more as an opportunity than a threat, as long as we manage the new risks in a systematic, unified and transparent manner,” concludes Knut Ørbeck-Nilssen. 

offshore UPDATE NO. 1 2012 |

staNDarDisiNg arctic challeNges

standardising arctic challenges as the ice melts, the arctic region is becoming more accessible. with an estimated 22 per cent of the world’s undiscovered resources lying beyond the arctic circle, the energy industry is looking north. trade routes are also opening up and will allow a shorter passage between certain areas. the nature of this environment – untouched, remote and wild – has made it as appealing as it is precarious over the past hundred years. Per olav moslet, Dnv’s programme director for arctic technology, discusses arctic safety issues in this article. teXt: SVEIN INGE LEIrGuLEN, dnv

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Photo: Dnv

staNDarDisiNg arctic challeNges

oFFshore uPDate NO. 1 2012 |

Photo: DNV

Standardising Arctic challenges

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Per Olav Moslet, Programme Director, Arctic Technology.

Fram – a three-masted schooner powered by a steam engine – was launched in 1892. She was reputed to be the strongest wooden ship ever built and the one that sailed closest to both poles. Guided by DNV Classification Rules, the vessel was designed and built by the famous ship constructor Colin Archer from Larvik in Norway to withstand the extreme effects of high ice pressure on the hull on its way to the North Pole. Fram’s capabilities in ice were demonstrated on her first expedition – to the North Pole with the scientist Fridtjof Nansen. Where other ships had been smashed to pieces by ice pressure, Fram’s innovative hull design raised her above the ice. The vessel returned home to Norway in 1896 as a great success. Two years later, Fram was heading for the Antarctic, carrying Roald Amundsen and his team on their way to becoming the first men to reach the South Pole. Once again, she withstood the strains and hardships of the polar oceans, successfully carrying the expedition to the Antarctic and back. Ice Class notations Not surprisingly, given our Norwegian roots, DNV has a long history of working with ships and structures in ice. The first requirements for additional ice strengthening were set in

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1881. In the years since the Fram expeditions, DNV has become the leading classification society for vessels working in ice and is continuously increasing the market share of both its maritime and offshore cold climate classification activities. This position is largely due to our independence, experience of harsh environments and, for more than a century, unchanging commitment to “safeguarding life, property and the environment”. We help the industry to manage the risks in the Arctic and Antarctic regions. Through its extensive experience, DNV has an in-depth understanding of the challenges of operating in the polar regions. Our rules set standards for safe operations in cold climates. Ice class and winterization rules are tailored to specific operational needs in different ice conditions. The winterization notations help ensure that the crew and essential systems can operate in freezing temperatures and icing conditions. Obviously, the correct application of such notations increases operability and reduces the risk of damage. Harsh offshore working environment Arctic environmental conditions will have a strong influence on the working environment and technical safety of offshore operations in the Barents Sea. Therefore, design requirements need to be considered in order to ensure that offshore units meet the facility integrity and operability requirements under these conditions.

conditions. To meet the Arctic’s working environment challenges, specific requirements are set as to system and equipment design, construction and operations that will influence the overall safety level. All systems, equipment and areas of a facility where the Arctic environment may impair safety, functionality or operability need to be evaluated with respect to the working environment. A systematic process for evaluating and selecting solutions is required to ensure that the risk level is as low as reasonably practicable. Finally, the evaluation process should be risk-reduction driven. Preference must be given to selecting permanent, technical solutions rather than temporary, operational or procedural solutions. It is important to select solutions that improve safety and the quality of the working environment without introducing adverse side effects. The main objective is to provide adequate protection for personnel so as to ensure their health, safety, performance and decision-making under the expected Arctic environmental conditions. The installation design should minimise exposure to spray, wind, cold and the accumulation of ice and snow. In order to provide such protection, the main principle is to enclose or shield working areas from the elements wherever practicable. Areas that are not fully or partially protected and where snow and ice may accumulate should be provided with anti-icing or de-icing arrangements as appropriate.

“Marine icing is a concern for several Statoil projects and there is a need for development of tools for icing predictions. Statoil will continue to address icing related issues and contribute to improved knowledge on the subject.” Kenneth Eik, Statoil

The general design philosophy must be that technical safety and the quality of the working environment on facilities in the Barents Sea are to be maintained at the same level as on other facilities not exposed to Arctic environmental

Designers should especially consider the danger to personnel from ice falling from structures such as cranes and derricks. The layout design can minimise this hazard by arranging work areas away from structures that are likely to accumulate snow and ice,

Standardising Arctic challenges

or protecting work areas with roofing that can withstand the impact of falling ice. Cold and wind chill exposure Arctic offshore operations expose workers to cold, windy and wet conditions. Working in a cold environment can cause several adverse effects on human performance and health, from discomfort, strain and decreased performance, to cold-related injuries and diseases. Due to the adverse impact of cold on human health and performance, as well as on work productivity, quality and safety, operators need a comprehensive strategy of risk assessment and management practices for offshore work in cold environments such as the Arctic. The main philosophy for reducing exposure to the cold is to keep outdoor operations to a bare minimum. As a guide, this means limiting the time that an individual is exposed to a wind chill factor of –10°C or colder. Frequently manned areas should be sheltered without exceeding the allowable explosion risks. Strategies and practical tools for assessing

15.6–21.6 m

MVD 250 µm

and managing cold risks in the workplace may be found in ISO standard 15743 and 15265. These standards support good occupational health and safety, and are applicable to offshore work in the Arctic. They include: ■■ models and methods for cold-risk assessment and management, ■■ a checklist for identifying cold-related problems at work, ■■ models and methods for individual cold protection, and ■■ guidelines on how to apply thermal standards and other validated scientific methods when assessing cold-related risks. Dealing with hazardous marine icing Interest in shipping and oil & gas activities in the Arctic has been growing during the past decade. In parallel, this increases the need for the proper prediction of sea spray icing. Experience from activities in cold weather regions indicates that ice accretion on vessels and offshore structures

‹‹

MVD 2000 µm

1.0+00 7.1e-01 5.0e-01 3.5e-01

13–15.6 m

2.5e-01 1.8e-01 1.3e-01 8.9e-02 6.3e-02 4.5e-02

9.8–13 m

3.2e-02 2.2e-02 1.6e-02 1.1e-02 7.9e-03 5.6e-03

0–9.8 m

4.0e-03

Figure showing the marine-icing simulation results from the MARICE project.

must be taken into account to provide safe and efficient operations. Marine icing (or “sea spray icing”), the focus of the MARICE project, causes hazardous situations due to e.g. slippery ladders and gangways, frozen and blocked escape and rescue routes and equipment as well as frozen process e quipment and valves, and is expected to reduce o perating efficiency or mission p erformance. Accidents may lead to injuries or even loss of lives, environmental damage and damage to assets. For smaller vessels, superstructure icing can even result in the loss of the ship, typically through capsizing. 

A substantial part of the world’s undiscovered hydrocarbon reservoirs are expected to be found in the Arctic. Exploration and production drilling in the Arctic is challenging due to the long distance to the existing infrastructure, 24-hour darkness and low temperatures, but drilling is a necessary step in order to extract the hydrocarbons.

The MARICE Project Objective: To improve the physical understanding of marine icing (‘sea spray icing’) and to translate this into numerical models and science-based guidelines for design and operations. To develop real-time icing severity maps for forecasting purposes and to assist in vessel routing to minimise icing effects, with emphasis on the waters north of Norway and Russia. Activities: Ice accretion-rate measurements have been conducted for two seasons on Svalbard, using custom-built equipment to estimate the rate of ice formation in natural conditions. Computational fluid dynamic (CFD) simulations show the areas of moving vessels most susceptible to sea spray and spray-derived icing. Measurements are also being conducted on rig-supply vessels operating in Arctic waters to assist and help verify the simulations.

2.8e-03 2.0e-03 1.4e-03 1.0e-03

Participants: DNV, the Norwegian University of Science and Technology (NTNU), Statoil and the Norwegian Research Council.

offshore UPDATE NO. 1 2012 |

Subsea 7’s Buoyancy Supported Risers

Subsea 7 buoyancy supported risers for Petrobras Based on an interview with Victor Bomfim, VP Subsea 7, conducted by Sergio Garcia, DNV

Subsea 7 is a seabed-to-surface engineering, construction and services contractor to the offshore energy industry worldwide. Subsea 7 provides integrated services and has a proven track record in delivering complex projects in deep water and challenging environments. In this interview Subsea 7 Victor Snabaitis Bomfim Senior Vice President for Brazil describes the current project for Petrobras. What has motivated this riser system concept to be developed? The buoyancy supported risers (BSR) concept was developed as a result of a design competition launched by Petrobras in 2009 to select a solution for what was requested as a de-coupled riser system for use in their deepwater pre- salt fields offshore Brazil. The BSR is a system which is de-coupled from the movements of the FPSOs on the surface. One motivation behind this type of concept was the requirement for special type of materials needed to deal with the unique characteristics of the products flowing through the pipes. Some of the production wells on the pre-salt fields have high CO2 and H2S content. Because of that, the standard coupled, flexible system is not an option since materials for those characteristics are still being developed / qualified. Therefore, Petrobras had to go for a steel solution, but even the carbon steel solution in itself is not applicable due

18 | offshore UPDATE NO. 1 2012

to the corrosive nature of the fluids, so the solution was to go with some form of corrosion resistant alloy (CRA) pipes. The concept was a result of the need for the type of material that is required to withstand the high pressure coming from the well and water depth which is beyond 2100 meters, added to the corrosiveness of the fluid being transported. The other main reason was Petrobras’ intent to de-couple the construction of the subsea system from the construction of the wells and the FPSO. This way the riser system can be installed without the wells and the FPSO being completed. The concept allows the construction and installation of the subsea system to be decoupled from the standard field development installation process where, the subsea system normally is in the critical path in order to connect the wells to the FPSO with both ends present. In response to the design competition, Subsea 7 presented the development of the BSR solution. The concept of the BSR is not exactly a new concept in the industry. Other operators have thought about this in the past, but Petrobras has developed the concept further. Back in 2004, Subsea 7 had been contracted by Petrobras to develop some procedures for the installations of the risers of this Buoy and to undertake the feasibility study of the concept. Based on our previous knowledge about this concept we believed that this

solution would be an ideal answer to the challenges that have been presented from Petrobras to the industry. What are the main elements of this Guará – Lula NE Riser System concept? The concept is very simple but at the same time it has it complexities. It is simple because you have a buoy in the subsurface moored at around 250 meters below the sea level, at which depth the effects of the surface, like the waves, do not interfere. Therefore, since flexible lines are already qualified for this depth, they’ll be connected from the FPSO to the buoy on a very stable condition. The deepest portion will connect the buoy to the wells through the CRA steel catenary risers. However, although the concept is decoupled, you need to analyze the system as a whole. In other words, the FPSO’s movements, how the FPSO is affected by the mooring, how the movements of the FPSO are transmitted to the flexibles, then to the buoys, the current, and finally the risers itself down to the seabed. The concept in itself is simple, but the interactions are very complex. Which elements would you highlight as technological breakthroughs? First one, in which DNV has been involved, is the qualification of using the reeling method for installing mechanically lined pipe. We have an exclusive

Photo: Gisella Francisca, DNV

Subsea 7’s Buoyancy Supported Risers

››

Victor Bomfim, VP Subsea 7

offshore UPDATE NO. 1 2012 |

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The BSR system – Buoy, Steel Catenary Risers, Flexible Jumpers and Tethers

agreement with a German company called BUTTING, who produce mechanically line pipe called BuBi® in which a CRA liner is installed inside a standard carbon steel pipe to give the necessary corrosion resistant properties. We have undertaken a joint programme that has been supported by DNV to get the type approval for the offshore reeling application. We have been through a number of qualifications and trials in order to prove that this mechanically lined pipe is fit for this type of offshore application. This is a programme that was concluded and type approved in 2010 and we are using this technology in this project. This was a major achievement because the reel-lay method for this application is

20 | offshore UPDATE NO. 1 2012

Illustration: Subsea 7

Subsea 7’s Buoyancy Supported Risers

››

A General view of the Buoyancy Supported Risers system

very cost effective. Being able to get this technology type approved was a major and important step for the success of this project. Another important technology that resulted as part of this process is what we call the Angular Connection Module, which is the system for the connection of flexible lines to the risers that are coming from the seabed. The risers that are connected to the buoy have a certain angle in order to connect to the flexible jumper, which is going to connect the buoy to the FPSO. This Angular Connection Module is something that has been specially developed for this project and was qualified by Petrobras following the guidelines as

recommended on DNV RP-A203 Qualification of New Technology. We have designed the system to make sure it would get the qualification process with Petrobras approved. This qualification was concluded a few months ago. This was the second important innovation point. The third technical breakthrough is the procedure for the actual installation of the buoy on site at 250 meters below the surface. The buoy has a number of compartments that need to be flooded or filled with air or nitrogen in a controlled manner, such that it can be lowered into position and provide the buoyancy that is needed for that situation. The whole procedure and methodology for actually

Illustration: Subsea 7

Subsea 7’s Buoyancy Supported Risers

››

A detailed view of the Buoy

installing the buoy in the position is also a unique and very innovative solution. There is also another important innovative element in this project which is the tension system to connect the buoy to the tendons. In terms of concept, the buoy is not actually moored with a spread mooring system but it is like a submerged tension leg platform. In order to control the tension Subsea 7 designed what we call the “top tensioning system”. The tendons are wire ropes with a length of chain connected to the jacking system attached to the buoy. In this specific case the development of this IP has been done together with Petrobras. What is the project’s present stage? The design engineering phase is almost complete. Fabrication of almost all the

components has started, and we are now developing the detail engineering installation phase. We aim to have all the main components fabricated by the end of the year to start installation in late 2012. How do you see DNV’s contribution to this project? DNV has been on board since day one and is the verification body for the project. The importance of the DNV team presence locally in our office in Rio integrated with the Subsea 7 team to expedite the whole engineering approvals, as well as in other locations, has been vital for achieving the present status. Subsea 7 will use DNV RP-A203 Qualification of New Technology as part of bringing its new technology to market. The whole involvement of DNV on the type approval of the

mechanically lined pipe, following DNV Recommended Practice, gave confidence to the stakeholders on this project. In summary, DNV’s role as an independent verifier is an important part of the project’s success. With both companies’ high value and investments on R&D, which other innovative projects would you highlight on the horizon for the partnership Subsea 7 and DNV? Talking about Brazil specifically, this is a small first step in a long journey. It’s up to us to make sure that the technology which will be used in developing these huge reserves in very deep waters will be there available to be applied. 

offshore UPDATE NO. 1 2012 |

SilverPipe

Take control from well to terminal with SilverPipe Reduce unplanned shutdowns with a timely response to integrity issues. Keep track of history as well as the current situation. Optimise your inspection programme using the results of risk-based inspection studies. Take control, from well to terminal, with SilverPipe. TEXT: KAIA MEANS

Manage, track and act Without a clear overview of the integrity of pipelines and components and the risk of failure, management cannot ensure appropriate action is taken to ensure safe operations and follow up the status as work progresses. SilverPipe is DNV Softwareâ&#x20AC;&#x2122;s integrity and risk management software, tailored to help operators continuously improve pipeline safety and reliability, thus reducing downtime and extending operational life. SilverPipe manages the integrity and risk of the entire infrastructure of onshore pipelines and facilities, and is equally fit for long haul lines, in-field installations and regional distribution networks. SilverPipe is used by customers for the safe and cost-efficient operation of complete oil infrastructures from wells to downstream terminals and gas transportation networks. The built-in capabilities for managing company integrity strategies and detailed integrity plans give integrity managers a powerful tool to stay on top of the situation and to ensure that inspections and assessments are carried out as planned. Our customers report increased efficiency, as SilverPipe delivers one system that provides an overview of the whole integrity cycle, supporting all activities that manage integrity and risk. A total configurable package supports company best practices and gives managers a situation map and risk log that includes company-specific work processes. GIS and inspection database integrations ensure seamless access to existing pipeline information.

22 | offshore UPDATE NO. 1 2012

Risk dashboard Our risk dashboard provides an unrivalled overview of your asset during its life cycle, including documenting risk and the decision-making process, control of integrity plans, and systems that allow managers to ensure that projects deliver as planned. It offers full traceability of integrity management events and decisions, streamlining controlling and improvement activities from well to terminal. The robust and documented interfaces between life cycle data management and integrity assessment tools ensure the consistency and quality of calculations and make integrity decisions documented and auditable. DNVâ&#x20AC;&#x2122;s assessment tools are based on 50 years of experience in delivering software to the industry, and cover calculations for strength assessment, code compliance and QRA as well as calculators for risk-based inspection planning (RBI) for components and tank systems. SilverPipe can be interfaced with DNVâ&#x20AC;&#x2122;s powerful and world leading Phast suite of software for dispersion modelling, hazard analysis and QRA. With more than 1,000 customers globally, Phast is the most wellvalidated and functionally comprehensive risk analysis software available for managing the risks associated with hazardous installations. SilverPipe adheres to industry-accepted codes such as DNV, ASME, NACE and API. The overall risk is aggregated, reported and used to optimise long-term integrity plans. Separate assessment of pipelines,

components and hotspots using qualitative and semi-quantitative approaches is the basis for risk aggregation. Phased implementation of comprehensive systems It is often a challenge for companies to get started with comprehensive risk and integrity management systems. It certainly requires careful planning, a phased implementation plan and trained staff. Through a modular software approach, powerful data import mechanisms, interfaces with existing company systems such as ERP, GIS and document systems, as well as by offering a skilled integrity management staff, DNV helps companies implement best integrity practices and ensure sustainable and reliable integrity processes. It is essential to document and track risk decisions. SilverPipe uses the risk matrix and best engineering concepts to enforce company policies and uniform working. Through pre-defined report templates, the periodical reports to authorities and other stakeholders are produced consistently and cost-effectively. SilverPipe closes the loop between assessment, inspection and mitigation with full traceability of integrity management events and decisions. The simplicity of its graphics, including colour-coded realtime status, keeps operators continuously informed. Life cycle management solutions help operators manage information, identify risks and make qualified decisions using

SilverPipe

Photo: Getty Images

Reduce downtime, extend operational life SilverPipe 6.1 brings new and enhanced capabilities to our customers worldwide: • PODS and APDM compliance • Configurable GIS integration • Revision management • Rich data viewer with aligned views of userselectable profiles • Rich survey results module configurable to customers’ import formats and result types (naming conventions) • Enhanced semi-quantitative risk module • Verification reports for DNV and ASME code checks and pressure containment calculations • Enhanced data validation • Corrosion and erosion and remaining life calculations

››

DNV Software is a leading provider of riskmanagement software to the energy, process and maritime industries – offering design, engineering, strength assessment, risk and reliability, QHSE and asset integrity management solutions. DNV Software is part of DNV and almost 300 DNV offices in 100 countries enable us to be close to our customers and share best practices and quality standards worldwide.

SilverPipe delivers one system that covers the whole integrity cycle, supporting all activities that manage integrity and risk.

configurable and scalable engineering software, accessing all relevant asset data, both current and historical. Meeting needs A full report on the use of SilverPipe for the integrity management of a pipeline system (oil export pipelines, oil storage tanks and satellite platforms) in the North Sea has provided valuable customer feedback. The report showed that SilverPipe improved

corrosion management through internal corrosion monitoring and mitigations. The interface between the disciplines covering the operation of topside facilities, wells and the pipeline system was also a focus area. The performed assessment study concluded that the main threat to the pipelines was internal corrosion. The only way to regain confidence in the integrity status was through in-line inspections, which were subsequently performed

for the multiphase and water injection pipelines. A capacity check was conducted together with a remaining life assessment in order to ensure the further safe operation of the pipelines. A strategy for how to control corrosion was established and both long-term and annual plans for internal inspection and monitoring were prepared. 

offshore UPDATE NO. 1 2012 |

The ship of the year

Introducing the ship of the year – the North Sea Giant We are at Bakkasund in the county of Austevoll, on a group of islands south of Bergen on Norway’s west coast. To get there you must travel by car and car ferry. This is where you find the picturesque headquarters of North Sea Shipping. Text: Magne A. Røe, DNV

24 | offshore UPDATE NO. 1 2012

Photo: North Sea Shipping

The ship of the year

offshore UPDATE NO. 1 2012 |

Photo: Magne A. Røe

The ship of the year

››

Hallvard Klepsvik, CEO and Knut Klepsvik, vessel owner, North Sea Shipping.

This is a company owned by four brothers and their brother-in-law Aksel Økland. Hallvard Klepsvik, one of the brothers, is the CEO of the company. He confirms that North Sea Shipping, like most ship owners or managers on Norway’s west coast, has its roots in the fishing industry. “We have fishing and the sea in our genes.” However, the North Sea Giant is about as far from a fishing vessel as you can get. The ship was given the prestigious Ship of the Year 2012 award by Offshore Support Journal, in strong competition with all types of offshore support vessels built worldwide throughout 2011. The ship was designed by Sawicon and built to DNV class by Metalships & Docks in Vigo, Spain. Why did you decide to build the North Sea Giant? “In our view, the offshore support markets are going further out to sea to more

26 | offshore UPDATE NO. 1 2012

remote areas with deeper waters, in other words there are more and more subsea operations. To cater for this, we saw the need for a ship with the largest deck OSV in the world and thus the idea of the North Sea Giant was conceived. “We specified a ship with a large area, great stability and good deck space and load capacity – a ship that can be at sea for long periods doing what it is designed for: lying still. The ship’s DP (dynamic positioning) ability is the best you can get – no ship in the world beats the DP characteristics of the North Sea Giant. The ship only burns 8 to 11 tons of fuel per day in DP mode, and that is significantly less than comparable ships. 80 to 90 per cent of the operational life of the North Sea Giant will be spent lying still, so to us the DP capability is essential – as it is to our customers as well – for the time being French company Technip.”

Have you tested the DP capabilities? “We tried the ship with a cross-current speed of more than six knots and it did not move from its position. We have installed five Voith Schneider propellers rated at 3800 kW and one Rolls Royce tunnel propeller rated at 2000 kW. The ship itself is 160 metres long and 30 metres wide. We have equipped the North Sea Giant with three separate engine and power systems, which allows the ship to maintain DP 3 operation with one engine room and power system out of service. This means three separate engine rooms and the power is distributed to six separate thruster rooms.” The North Sea Giant’s features are impressive. The deck cranes must also be powerful? “That’s correct – the main mid-deck knuckle boom crane has a capacity of 400 tons and a 3,000-metre single line wire,

Photo: North Sea Shipping

The ship of the year

while the aft crane can lift 50 tons with a 2,000-metre single line wire. The ship can handle deck loads of up to 8,800 tons and there are two ROV hangars on either side of the deck at the base of the ship’s superstructure. These are protected by hydraulic steel doors to provide shelter for the ROVs and comfort for the ROV operators. “There are 120 beds on board, 58 in single and 31 in double cabins, all the cabins are equipped with entertainment systems, satellite TV, radio and internet and there is even a cinema on board. The ship has DNV’s Comfort Class and Clean Design notations. “To summarise the ship: it is one of the largest and most advanced subsea construction ships ever built, offering new levels of advanced marine operations. Considering its size, the ship is also unparalleled in terms of redundancy. In my view, the ship is ideal for tasks related to subsea

construction, well intervention, top-hole drilling, cable laying, pipe laying and much more.” Are you likely to order a sister ship to the North Sea Giant? “When we ordered the ship, there was a global financial crisis making funding hard to come by for the entire shipping industry. However, we still had a strong belief in our project and ordered the ship from Metalships & Docks – and we have not regretted this. Building a sister ship depends entirely on the market and if a customer comes to us with a five-year horizon on a contract for a new building, we will order one. “When looking at the future of the market, with offshore wind farms coming as well as cable laying and well operations, I believe there is a good chance of a future contract without having any concrete plans

right now as to when. There are plans for some 1,000 wind generating units in the North Sea alone, and ships like the North Sea Giant will be needed to install the systems. Add the trends towards deeper waters, more remote waters and colder climate operations, and we are indeed optimistic about the future.” North Sea Shipping has managed and owned offshore vessels since 1984. The company fully operates two offshore vessels, has part ownership of nine offshore vessels and two fishing vessels and fully owns the North Sea Giant. 

offshore UPDATE NO. 1 2012 |

Software standard gains momentum with new drilling rigs

Software standard gains momentum with new drilling rigs Songa Offshore’s latest North Sea drilling rig will be built to DNV’s standard for managing complex, software dependent systems and, as the first of a comprehensive newbuilding program, and the first full-blown application for DNV, the project is expected to set a new industry standard in software management. Text: Wendy Laursen

Songa Offshore of Norway has specified DNV’s ISDS standard for integrated software dependent systems for the first of their seventh generation semi-submersible drilling rigs being built specifically as Stat oil’s new work horses for the Norwegian Continental Shelf. Although pilot tested on a number of other projects, it will be the first full-blown application of the standard to a newbuild and the project participants, as well as other key industry stakeholders, are preparing for its acceptance as a new industry standard. The ISDS notation establishes a methodology that aims to minimise software integration errors and delays in projects that involves complex, software dependent systems. The notation includes the development of quality assurance processes that will last throughout the drilling unit’s operational lifetime. Statoil has much to gain from a successful implementation of ISDS as the company has plans for several new drilling units tailor made to work on the mature fields of the Norwegian Continental Shelf. Two Category D units designed to perform drilling, completion and heavy intervention activities 20 per cent more efficiently than the existing fleet have already been ordered by Statoil from Songa Offshore and the order for DSME in Korea includes the option for two more. Scheduled for delivery in 2014, they will be able to operate at water depths of 100–500 metres and drill wells down to 8,500 metres. While

28 | offshore UPDATE NO. 1 2012

tailor-made for mid-water segments on the Norwegian Continental Shelf, the design is also suitable for other regions and can easily be converted for work in deep water, high pressure high temperature operations and Arctic operations. As charterer and operator, Statoil sees significant benefits from applying ISDS including reduced risk of delays during construction and improved control over reliability, availability, maintainability and safety once the units are operational. “Software integrity is important for us as we embark on this project,” says Jan Magne Gilje, technical coordinator for Cat-D in Statoil. “Statoil is working hard to utilise new technology to increase recovery and extend the life of the fields on the Norwegian Continental Shelf. We are applying innovative thinking on everything about the Cat-D midwater rigs. This requires solid change management processes and ISDS will help us do that.” Statoil believes the key to maintaining today’s production level on the Norwegian Continental Shelf towards 2020 is improved recovery from existing fields and fast and efficient development of new fields. Fit for purpose rigs and utilisation of technology will be important measures to increase recovery and extend the life of the fields. ISDS supports these ambitions starting with the first Cat-D deliveries and potentially also to other rigs. Software reliability is clearly and consciously an important part of such a project.

DNV has begun the familiarisation process with project participants. Steven Durham, Songa’s Cat-D project director is on location in Korea. “I can see that ISDS is a good concept,” he says. “Software control and management of change have been problematic in the past so we openly accept this initiative. We want it to work. Right now, here in Korea, we are all thinking through what it means for us individually as well as at a company level.” The new avenues for communication and control that ISDS establishes between owner, yard and vendors will be developed during engineering, construction and ultimately commissioning. “When we get all the third party equipment on site in the yard, then we will see the real results,” says Mr Durham. “Aside from the potential for software glitches to delay a project, they can ultimately be dangerous to those on board. Therefore, we all want ISDS to be successful.” For DSME, it means working with many suppliers to meet the ISDS requirements and, as the first yard to be involved in such a project, they hope to gain a competitive advantage from its success. Sverre Fjereide, project controls manager for DSME, is cautiously optimistic that it will ease commissioning problems and reduce after-delivery support efforts. “We are the guinea pigs,” he says. “We hope to get a better focus on engineering and testing requirements that can be specifically applied to software as this has been less than ideal in the past. ISDS will not solve all problems but it will

Software standard gains momentum with new drilling rigs

Photo: DNV

unit and that any weaknesses hopefully improve the situare not propagated throughout ation. If we can get a 50 per a fleet from one delivery to cent improvement in softwarethe next,” says Rolf Benjamin related delays during commisJohansen, DNV’s project direcsioning, then it will be a big tor for systems and software success especially given the reliability. complex nature of such proDNV applies methodologies jects and their time limits.” that have proven effective in For Jon Fredrik Lehnthe aerospace, telecommunicaPedersen, Kongsberg’s gentions, defence and automotive eral manager for drilling and industries. Their experience offshore automation, the with ISDS from previous prointerface problems that arise jects with Seadrill, Dolphin between suppliers during Drilling, Odfjell, Total and commissioning can be time Statoil indicates that applying consuming, expensive and ›› ISDS ensures that software integrity is maintained throughout the lifetime. the ISDS class notation can can introduce an element of easily save USD 6–20 million by risk that should be avoided addressing potential problems with ISDS. Working with ISDS early in a project and thereby means that the necessary interavoiding the delays caused by faces are clearly documented the need to re-work software. and approved by class early on The notation provides a and they then form the basis framework with industry-wide for all design, engineering and reach for systematically assurfactory acceptance work. Too ing the quality and perforoften re-working is required mance of software-dependent during commissioning when systems and many key stakeit becomes apparent that the holders are already gaining parties involved have not put confidence with it. Some the required effort into the inicompanies that are yet to be tial specifications, he says, and directly involved in other prowhen problems occur, there is jects have already approached always a lot of discussion about DNV and asked them to assess who is responsible. ›› DNV has developed a standard for Integrated Software Dependent Systems, their delivery practices for Although, ISDS may mean ISDS. compliance. that Kongsberg puts extra “What is unique about the resources into the early phase DNV ISDS standard is that we look at sysintended to ensure operability and effiof the project, at least until they gain more tem integration as a whole, for the entire ciency, especially for non-safety critical sysexperience with DNV’s requirements, Mr drilling rig or ship, and we also make sure tems. However, software related downtime Lehn-Pedersen believes the system is comour approach is flexible enough to fit in can be a problem throughout the life of a mon-sense and practical and follows the with and augment current good industry drilling unit as most software is designed same principles that they have developed practices,” says Mr Johansen. These characwith a three-year lifecycle compared to the in-house over time. Since 2008, Kongsberg teristics and the foothold they have already 20–25 year design life of the hardware. has been delivering dynamic positioning, gained in the industry places DNV in a ISDS places particular focus on softpower management and integrated autoposition of leadership. “DNV believes that ware service providers, but roles and mation systems to about 20 latest generaall new drilling units and major modificaresponsibilities are defined for all parties tion drilling units each year. Mr Lehn-Pedtions should apply ISDS. It will create value involved. “With the diagnostic functionalersen believes ISDS would have been very for all parties involved, and even applied ity and remote access that is incorporated useful over this time. “It is definitely time retrospectively to operational units, it into drilling units now, it is really imporfor this to happen now,” he says. improves the ongoing safety and reliability tant that software integrity is maintained While existing class rules work to ensure of drilling operations.”  throughout the operational lifetime of the a drilling unit or ship is safe, they are not

offshore UPDATE NO. 1 2012 |

A plug-in solution

A plug-in solution The offshore wind arena is currently flooded with a number of un resolved questions. What’s the best way to bring electricity ashore from wind farms far off the coast? Should there be a cable running from each wind farm to the shore, or should we create an offshore electricity grid, to simply plug in the production plants? Is it better to use AC or DC? On a frequent basis, governments, project developers and network operators ask DNV KEMA Energy & Sustainability to investigate and answer these questions. Text: Marjolein Roggen, DNV KEMA

All of the countries fringing the North Sea currently have ambitious plans for the realization of offshore wind farms. By 2020, for example, the Netherlands intens to have 6,000 MW of capacity installed at sea, while Germany and the United Kingdom are aiming for 15,000 MW and about 30,000 MW, respectively. Not only will the erection of so many offshore turbines be an enormous operation, but getting the electricity they produce to shore is quite an undertaking. Individual cables As the number of offshore installations grows, the idea of connecting each of them to the onshore grid by its own cable begins to look less attractive. There are drawbacks for project developers, for the authorities and for the environment. For every cable project, a new permit procedure has to be followed, and realization is an expensive and timeconsuming undertaking that puts the continuity of supply at risk. In most cases, the creation of a sea-to-shore connection is also outside the core competence of the developer or proprietor. Add to the mix the considerable energy losses associated with long-range transmission and the need to have cable crossings along the coastline at numerous points, and it’s easy to see why alternative solutions are being examined.

30 | offshore UPDATE NO. 1 2012

Making the connection As early as 2003, the Dutch Ministry of Economic Affairs asked KEMA and others to investigate the potential technical, licensing, regulatory, and financial hurdles that must be addressed before connecting 6,000 MW of offshore capacity to the onshore grid. “It’s not only about the connections themselves, but also about the need to upgrade the infrastructure on land,” explains DNV KEMA’s Frits Verheij, “Feeding power into the grid from offshore wind farms will result in additional loads on the existing substations and cables.” “With the Dutch government’s sustainability ambitions in mind, we began making practical preparations for an offshore electricity grid in 2008,” recalls Lex Hartman of Dutch transmission system operator TenneT. “The spatial planning for bringing cables ashore at the Dutch coast has already started.” In contrast to the way things work elsewhere, obtaining the necessary planning license in the Netherlands is by no means a formality. The developer of a wind farm is the one responsible for connecting the facility to the onshore grid. “Making TenneT responsible for an offshore electrical infrastructure would have various economic benefits, including lower capital costs and purchasing advantages,” affirms Hartman. “Coordinated grid development planning would also reduce

the risk of over-investment or underinvestment, and would be in line with the way the European market is developing. It would also pave the way for the possible long-term creation of a shared renewable energy ‘supergrid’ spanning the North Sea.” Considering the alternatives KEMA was initially asked by TenneT to identify and analyze the technical and policy developments associated with the attainment of an offshore grid connecting various European countries. Later, we also came up with a range of technical options and a decision-making methodology toselect the most suitable solution, taking account of various parameters, such asdistance to the coast. “For this study, we worked on the basis of offshore wind farm ‘building blocks’, each with a collective capacity of 1000 MW. We then assessed what the best alternatives were. First, if the wind farms were sited 30 kilometers from the onshore connection point, and then if they were 120 kilometers away,” recounts Verheij. “We considered energy losses, reliability, environmental impact, security of supply, market maturity, vulnerability of the technology to future developments, flexibility and degree of innovation. And, everything was set off against the cost. For each offshore distance

A plug-in solution

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Photo: TenneT

BorWin Alpha is the first HVDC station of the world installed on an offshore platform. It is used for the conversion of the power generated in offshore wind park BARD 1 from AC into DC with a voltage of 150 kV.

option, we further developed the threemost preferred alternatives.” Preferred connection The study indicated that if the wind farms are at a distance of 30 kilometers from the shoreline, a 150 kV AC connection was always preferable. The various options for realizing the connection were individual cables, a pathway with several parallel cables, and a set-up where the wind farms feed

an offshore substation, connected to the land by several cable circuits. If the wind farms are located 120 kilometers from the land, the differences are more pronounced. A 150 kV AC connection with an offshore substation remains an option, but 150 kV and 300 kV HVDC connectors coupled with an offshore converter station are more economically attractive options, mainly due to substantially lower energy losses.

Experience As of yet, experience with the type of plug-in solution envisaged is generally lacking. “You would have to deal with a rough, wet, salty and windy environment, implying some pretty demanding design requirements,” says Verheij. “And, if anything goes wrong, you couldn’t necessarily get someone on site on short notice.” KEMA is therefore drawing up a schedule of design requirements for a closed substation. TenneT can also draw on experience gained by former RWE’s Transpower, which is working on offshore wind projects up to 200 kilometers off Germany’s North Sea coast. “The first plug-in connection using HVDC technology has already been realized,” Hartman points out. “What made this project unusual was the way the customer and KEMA worked together,” says Verheij. “Evaluation of the various options was made in the context of intensive interaction among experts from various disciplines within TenneT and KEMA, covering fields as varied as technology, economics and regulation.” “This study provided us with insight into the various alternatives and the associated cost,” concludes Hartman. “As a result, we now have a number of basic building blocks that can be used in the further development of the offshore grid.” 

offshore UPDATE NO. 1 2012 |

Self-elevating units

New DNV drive results in updated rule book for self-elevating units A new dedicated rule book symbolises DNV’s new drive focusing on the self-elevating unit segment; based on DNV’s wide-ranging offshore classification experience and renowned Offshore Standards but with a clear focus on the specific design considerations for self-elevating units. It is easy to use and makes clear what is required to comply with DNV and international regulations and standards. Adaptations to the traditional Offshore Standards include additional class notations and aligned material and jacking system requirements based on feedback from industry experts. TEXT: MICHIEL VAN DER GEEST, DNV

“This is exactly what our jack-up drive this year has been about,” explains DNV’s Mobile Offshore Unit Segment Director Erik Henriksen. “To make sure we understand the needs of this market segment and provide the focused service delivery that covers these needs. The rule book is an element in this service delivery, but our commitment to the jack-up segment is allencompassing, and includes the establishment of service centres and development of our resources, dedicated procedures and instructions.” Focus There are many renowned technical standards available in the market which ensure that safety and reliability standards are met even by state-of-the-art design solutions on the edge of the operational and design envelope. This makes the standards complex and they do not always give the clear guidance designers, yards and owners like to see. This clear guidance is especially important in the self-elevating unit market. “The decision to prepare a dedicated rule book to give this clear guidance is therefore a strong signal of our focus on meeting the specific needs of the JU market,” explains Michiel van der Geest, DNV’s Offshore Class Product Manager

32 | offshore UPDATE NO. 1 2012

and the person responsible for this service development. “But besides this signal, the practical work of collecting information and defining the standard revealed all the specific considerations that have to be taken into account; specific considerations which are now available to all users and other stakeholders.” Understanding The jack-up market has its own considerations. Even though formally jack-ups are covered by the Mobile Offshore Unit regulations and safety standards, they contain elements which are more related to fixed platforms. If these two worlds are not viewed in the right perspective, more stringent and expensive requirements may easily be stipulated without having a positive effect on safety. It must be clear that DNV has incorporated this understanding into its new rules. Another new element of the rules is the voluntary notation Enhanced Systems (ES). “We had a clear desire to align ourselves with accepted and proven market standards” reveals van der Geest when asked, “at the same we do not want to forget those yards and owners looking to improve their unit’s safety and reliability in a cost effective way”. To cover this need,

we have taken our accumulated knowledge and experience and collected the relevant requirements and acceptable design solutions in the ES notation. The message is clear: the new Jack Up rules present an overview for IMO MODU code compliance level in a wide spectrum of operation at the same time include the ES notation for those looking for increased safety and reliability in a cost effective way. Commitment As stated above, DNV’s jack-up drive is not limited to the new rule book alone; new service centres are being established to optimise communication and operations with customers in the selfelevating unit segment. These service centres also act as in a network connecting all the jack-up relevant knowledge and expertise in DNV’s worldwide organisation. In addition, the drive has adapted procedures to make sure we are aligned with the customer’s specific operational profile. To sum up, the service delivery to the jack-up segment is supported by a suite of additional DNV services that includes Hull Integrity Management, training courses and a benchmark service. All these help an owner to control and optimise assets and reduce downtime. 

Self-elevating units

Photo: 2012 Seadrill Limited

Simplicity – compliancy level – focus – knowledge – understanding

››

The Independent Leg Cantilever Jackup Offshore Defender.

offshore UPDATE NO. 1 2012 |

Barrier management for offshore safety

Barrier management for offshore safety Without question, the oil and gas industry has greatly improved its occupational, or personal safety and injury, performance over the past 20 years, as shown in Figure 1.

Photo: DNV

Text: Blaine Collins and Robin Pitblado, DNV

››

Blaine Collins, Director, Divisional Staff, Division Americas.

Today, there is considerable focus on reducing the major accidents – the blowouts, explosions, pollution events, collisions and similar accidents, collectively referred to as process safety accidents. Significant programmes and regulatory actions have honed in on the prevention and mitigation of major accidents and it now appears that barrier management may very well be the most effective tool to prevent or reduce the consequences of major accidents. Indeed, consider the history of process safety management. First, the US Occupational Health and Safety Agency (OSHA) issued a process safety standard for use in onshore process facilities in 1992. Then, in 2004, the American Petroleum Institute issued Recommended Practice 75, “Recommended Practice for Development of a Safety and Environmental

34 | offshore UPDATE NO. 1 2012

››

Robin Pitblado, Director SHE Risk Management.

Management Program (SEMP) for Offshore Operations and Facilities”. The Bureau of Safety and Environmental Enforcement (BSEE) recently announced its new requirements for Safety and Environmental Management Systems (SEMS), which generally extend the requirements contained in the API Recommended Practice. One of the targeted means to enhance offshore safety is the use of a Health, Safety and Environmental case. Briefly, the purpose of an HSE case is to identify all significant risks over a facility’s operational life to show that there is adequate control of these risks and, ultimately, to develop an emergency plan to address any accident. In fact, the International Association of Drilling Contractors (IADC) has issued guidance on HSE case content, including the interactions and

Barrier management for offshore safety

Barriers to eliminate & prevent causes of hazardous event

Occupation Safety Performance 4

Barriers to control consequences & effects

3.5 Corrosion

API BP Chevron Texaco ConocoPhillips Dow ExxonMobil Shell Concawe

2 1.5 1

THREATS

2.5

Consequence 1

Mal-operation

Ignited – Jet fire

Cause 2 Barrier decay mechanism controls

Consequence 2

TOP EVENT

Barrier decay mechanism controls

Loss of containment

Barrier decay mechanism

0.5 0 1992

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No ignition

Hazard

Cause 1

EFFECTS

Reportable incidents per 200,000 manhours

e.g. flamable gas

Risk management hierarchy 1994

1996

1998

2000

2002

2004

2006

2008

2010

Elimination

2012

Figure 1: Occupational Safety.

responsibilities of key parties, such as the well owner, drilling contractor, well services company and other contractors. The safety barrier approach, more specifically barrier management, is based on two models, the Swiss cheese accident model and the bow tie barrier diagram. For this, imagine a row of Swiss cheese slices in which each slice is a barrier and the hole represents a weakness in the barriers that may fail to prevent an accident. If the holes line up, which may occur when multiple barriers are not in place or properly functioning, accidents can occur. This simple Swiss cheese model is surprisingly accurate – the more barriers, Swiss cheese slices, the safer the facility, and the smaller the holes, the smaller the weaknesses in the barrier. The tool that captures the Swiss cheese concept and carries it further is the Bow Tie Barrier Diagram (Figure 2). For each “Top Event”, such as a major leak, blowout, or explosion, all of the threats, such as corrosion, equipment malfunctions or failure to follow operating procedures are shown on the left, while the effects, such as asset or environmental damage are shown on the right. The prevention barriers are then between the threats and the top event, while the mitigation barriers lie between the top event and the outcome.

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Prevention

Detection

Mitigation

Emergency

Figure 2: Bow Tie Barrier Diagram.

The barrier diagram risk approach provides benefits for operations that are not seen in a Preliminary Hazard Analysis (PHA), which tends to consist of lengthy text documents intended for designers or regulators, or Quantitative Risk Assessment (QRA), which is highly numerical and mostly addresses design issues. While both are important, neither is suitable for operations, maintenance or contractor personnel – but barrier management was developed specifically to meet operational risk management needs. Usually, there are 2–5 barriers in each pathway leading to and from the top event. Barriers can be a specific control, such as a hardware item, a technical or automation feature, a management system or an administrative programme. In effective barrier management systems, each barrier is monitored by operating personnel, its status is known at all times, and additional information on each barrier is available, such as the owner responsible for the barrier control, cross-references to specific procedures or maintenance plans, or minimum performance standards for the barrier. Experience has shown that around 20 bow ties can capture the most important risks and controls for an offshore facility. Barrier management is an effective tool to connect facility operations with HSE cases, design features and regulatory requirements in an integrated fashion. 

offshore UPDATE NO. 1 2012 |

takiNg Deepwater pipeliNes tO the x-streaM

taking deepwater pipelines to the X-stream dnv has a safe and cost-efďŹ cient concept in the pipeline the deepwater gas transportation market will experience massive investments and considerable growth over the coming years as operating companies go even deeper to find and recover new resources.

Photo: getty images

teXt: aSLE VENĂ&#x2026;S, dnv

36 | oFFshore uPDate NO. 1 2012

Taking deepwater pipelines to the X-Stream

“X-Stream is based on established and field-proven technologies which have been innovatively arranged to provide a new solution”

This will result in a number of new technical and operational challenges, as we face a future where operators are forced to push the frontiers of exploration in order to meet energy demand. The industry is delving into deeper and more remote fields and new exploration activities are also heading for ultra-deep waters. These fields are often located several hundred kilometres from land, in water depths in excess of 2,000 metres. We also see several gas pipeline projects that are planning to cross deeper and deeper sea passes, e.g. GALSI (2,824m water depth), SouthStream (>2,000m water depth), and SAGE (Middle East to India 3,400m water depth). Deepwater pipelines pose a number of challenges and in particular long-distance gas transportation in deep water is an increasing issue due to its cost. The safe and cost-effective transportation of oil and gas in pipelines in deep and ultra-deep waters is a growing challenge worldwide, and safe and new solutions are needed. DNV has developed a new pipeline concept called X-Stream, which can significantly reduce the cost of deep- and ultra-deepwater gas pipelines while still complying with the strictest safety and integrity regimes. This long-distance gas transportation concept can reduce the wall thickness of deepwater gas pipelines by utilising a unique system to control the differential pressure. X-Stream can reduce both the pipeline wall thickness and time spent on welding and installation compared to deepwater gas pipelines currently in operation. The exact reduction in the wall thickness depends on the water depth, pipe diameter and actual pipeline profile. Typically, for a gas pipeline in water depths of 2,500m, the wall thickness can be reduced

by 25 to 30% compared to traditional designs. Reducing the wall thickness of the pipeline by 25–30% could save in the order of 10% of the installation cost. There are also other advantages. For example, the concept can allow a larger diameter with the same wall thickness and also reduce the consequences of a potential accidental flooding of the pipeline during installation. Implications for industry The cost of producing pipelines will decrease if the X-Stream concept is used, as less steel is required to make the pipe. The reduced thickness also means that manufacturing using higher grade steel will be possible. Installation costs can be slashed due to the lower welding times and the new method also results in increased lay rates. The concept can have significant implications for projects around the world. In particular, X-Stream will be highly applicable to the recent finds in pre-salt fields off the coast of South America. Located 330km from the coast, these pose a number of exploration and gas transportation challenges which can be alleviated by using the new concept. It is also relevant to deepwater developments in the Gulf of Mexico, Eurasia and West Africa, as well as any gas trunk lines crossing deep-sea passes. The X-Stream concept may also represent an alternative to the current solution of deploying floating LNG plants combined with LNG shuttle tankers for such fields. X-Stream is based on established and field-proven technologies which have been innovatively arranged to provide a new solution. The X-Stream’s integral principle is the maintenance of a constant internal

pipeline pressure. The concept is based on the inverted High Pressure Protection System (i-HIPPS) and the development of inverted Double Block and Bleed (i-DBB) valves. More than 20 subsea HIPPS systems are currently in use worldwide to prevent sudden pressure rises in pipelines. DNV is inverting this well-established system to prevent too large a differential pressure during the pipeline’s lifetime. DNV conducted a concept risk analysis to identify the major threats and mitigate the risk involved in the concept and one significant issue was identified. In order for the concept to function effectively, there is a requirement for 100% internal leakproof i-HIPPS valves, at least for the secondary HIPPS valves. As a result, i-DBB valves were developed. By utilising i-HIPPS and i-DBB valves, the X-Stream system immediately and effectively isolates the deepwater pipe if the internal pressure starts to fall. In this way, the internal pipeline pressure can be maintained above a critical level for any length of time. Implementing X-Stream The challenge is to avoid a pipeline collapse over hundreds, or thousands, of kilometres, caused by the loss of internal pressure through a leak or rupture of the pipe during operation. Current deepwater gas pipelines have traditionally been built with very thick walls, using large quantities of steel and specialised equipment for milling. Due to quality and safety requirements, the number of pipe mills capable of producing this type of pipe is limited. They also use extremely thick and costly buckle arrestors. When installing pipelines, the heavy weights are difficult to handle and the

offshore UPDATE NO. 1 2012 |

thick walls are challenging to weld. Given the more demanding composition of current deepwater pipes, the number of pipe-laying vessels capable of handling this kind of pipeline is limited too. Demand is expected to increase for the few specialist milling and laying facilities for deepwater pipelines, which will further increase the costs of using conventional methods. During installation or operational shutdowns, gas pipelines at such extreme depths have to withstand high external pressures without imploding. X-Stream has introduced a new method to deal with this pressure problem without relying purely on material thickness to ensure the integrity of the pipeline and stop the collapse of the pipe wall. By controlling the pressure differential between the pipeline’s external and internal pressures at all times, the amount of steel and thickness of the pipe wall can be significantly reduced compared to today’s practice – depending on the actual project and its parameters. The X-Stream concept complies with common pipelines codes such as ISO and DNV-OS-F101, ensuring that safety is not compromised. When the new pipeline concept is being installed, it is necessary to fully or partially flood the pipeline to control its differential pressure. After this, the cleaning and gauging of the pipeline can commence as normal and the pipeline can then be dewatered and dried for operation. The i-HIPPS and i-DBB systems ensure that, during operation, the pipeline’s internal pressure can never drop below

38 | offshore UPDATE NO. 1 2012

Photo: DNV

Taking deepwater pipelines to the X-Stream

the collapse pressure – plus a safety margin. This maintains a certain minimal internal pressure in the pipeline during its lifetime. X-Stream consists of a series of valves and pressure transducers linked to a control system. The main i-HIPPS valves are located above water to ensure easy access for the maintenance, inspection, testing of the valves, etc. The main i-HIPPS system will activate on a low pressure signal from the pipeline. This ensures a minimum internal pressure in the pipeline at all times as long as the pipeline is free from leaks or ruptures above the collapse-critical area. If the pressure continues to fall due to an internal leak in the main i-HIPPS valves and the pressure is approaching the critical collapse level, the i-DBB system is activated and the pipeline is isolated by a viscous substance or gel being pumped under high pressure into the space between the i-DBB

valves to stop leaks from the higher pressure side. This is a central component of the X-Stream concept which ensures the integrity of the pipeline. What is termed the ‘collapse-critical area’ is the depth at which the external pressure can compromise the pipeline. If leakage or rupture of the pipeline occurs above this level at the rig or near the shore, then the secondary i-HIPPS system will be activated. The secondary i-HIPPS system is located below the collapse-critical area. If disaster strikes and there is a leakage or rupture of the pipeline in shallow water, the pressure will fall and the i-HIPPS valves will close. The i-HIPPS activates on a low pressure signal to prevent pressure in the pipeline from dropping below the predetermined minimum and it immediately isolates the deepwater pipe if the pressure begins to fall. This ensures that the

Photo: DNV

Taking deepwater pipelines to the X-Stream

internal pipeline pressure is maintained above the critical level and protects the pipeline from collapse due to excessive external pressure. When the trigger is activated, the valves and actuators close to maintain the pressure within at all times. The below-water i-HIPPS valves are placed below the collapse-critical depth. Should the below-water i-HIPPS valves have an internal leak and the internal pressure reaches a critical level, a small bleed valve is opened to the surrounding water and the seawater will flood the void between the i-DBB valves. The sea water pressure here will ensure that the pressure never drops below the critical level. Leakage or rupture below the critical collapse depth limit will not be collapse critical because the high external pressure will prevent the loss of internal pressure below the critical level. If there is leakage, then it will result in an in-flow of water

rather than gas leaking out, the same as would happen with a traditional gas pipeline in deep water. It will also be important to maintain the minimum pressure in the pipeline during pre-commissioning. This can be done using produced gas separated from the water in the pipe by a set of separation pigs and gel. This technology is not new to the industry as this method has already been initiated as standard practice by several oil companies. From concept to reality DNV has been instrumental in developing and upgrading the safety and integrity regime and standards for offshore pipelines over the past decades. Today, more than 65% of the world’s offshore pipelines are designed and installed in accordance with DNV’s offshore pipeline standard. The company has also been involved in several

deepwater projects over the past years, e.g. Oman to India, Bluestream, Perdido and Ormen Lange. A global team of highly skilled engineers combining youth and experience, headed by DNV in Rio de Janeiro, Brazil, and including Oslo, Houston and Cape Town, is behind X-Stream. The new concept has been launched following significant research, development, engineering and industry input. The DNV study is a concept, and a basic and detailed design will need to be carried out before the X-Stream concept is realised in a real project. DNV is working with the industry to refine and test the concept. DNV is confident that, by further qualifying the X-Stream concept, huge financial savings can be made for long-distance, deepwater gas pipelines without compromising pipeline safety and integrity. 

offshore UPDATE NO. 1 2012 |

Energy EfFIciency for OSVs

Energy efﬁciency for OSVs Today, two segments of the maritime industry that continue to remain buoyant and attract a lot of investment and new orders are the LNG carrier and Offshore Support Vessel (OSV) markets.

Photo: Magne A. Røe

Text: Tony Teo, DNV

››

Tony Teo, Business Development Director, Maritime North America. Picture taken on a Teekay tanker a few years ago.

LNG carriers’ day rates continue to surge ahead and are currently at over USD 150,000 per day, while the OSV segment, depending on vessel features, is averaging rates of USD 30,000 a day. The annual return on revenue of an LNG carrier and OSV are 23 per cent and 22 per cent respectively, representing the best investments in the maritime market today. The quest for deepwater activity has brought with it the need for OSVs with DP capabilities, and rig deliveries have kicked up the need for more sophisticated OSVs. Companies that have recently announced orders include Hornbeck, with sixteen vessels, Harvey Gulf, with

40 | offshore UPDATE NO. 1 2012

four LNG-fuelled OSVs, and BP Shipping, which is behind four OSV orders in Korea. In Brazil, an estimated one hundred OSVs will be needed for its increasing offshore activities. Environmental legislation Meanwhile, all OSV operators need to be aware of the environmental considerations involved in running their fleets. Today, the shipping industry has an annual CO2 emission level equivalent to that of the entire nation of Germany. In the past, shipping was “exempt” from emissions legislation since it was international and therefore difficult to regulate. However, there has

been a steadily increasing focus on shipping over the last decade, which is why the industry has to be proactive. For example, the waters along the coasts of North America will soon be an emissions control area (ECA). In March 2010, the International Maritime Organization (IMO) amended the International Convention for the Prevention of Pollution from Ships (MARPOL), designating specific portions of North America as an ECA, and this will become enforceable in August 2012. The ECA extends 200 n-miles from North American shores and includes all inland waterways (including the Great Lakes) as well as portions of Alaska and

Photo: Harald M. Valderhaug

Energy EfFIciency for OSVs

››

The DNV-classed, LNG-powered Viking Energy.

offshore UPDATE NO. 1 2012 |

Energy EfFIciency for OSVs

42 | offshore UPDATE NO. 1 2012

Photo: Per Sverre Wold-Hansen

Globally, CO2, SOx and NOx are key regulatory issues now. SOx and NOx regulations are in place, with stricter regulations coming into force. CO2 regulations are under development, but subject to tremendous political difficulties. The refinery industry, too, has already warned that it will have difficulties in meeting the demand for low sulphur fuels when the introduction of the IMO’s global 0.50% sulphur limit comes into force in 2020, let alone the ECA sulphur limit in 2015. Over and above specific emissions-related measures, in 2010 the IMO announced an initiative to introduce an Energy Efficiency Design Index (EEDI), a Shipboard Energy Efficiency Management Plan (SEEMP), Energy Efficiency Operational Index (EEOI), and Market-Based Measures (MBMs). MARPOL Annex VI, which enters into force on 1 January 2013, makes the EEDI and SEEMP mandatory. The EEDI requirements will apply to new ships above 400 tonnes. The EEDI is a set of targets for specific ship types against which newbuildings will be benchmarked. The regulations call for designs to be more efficient than the benchmark, which becomes tougher over time for subsequent newbuildings. The amendment stipulates that an International Energy Efficiency Certificate (IEEC) is to be issued on the first renewal or intermediate survey after 1 January 2013. The certificate requires, amongst

Photo: Per Sverre Wold-Hansen

Hawaii. This applies to all ships in the US ECA, including vessels registered to nations that are not party to MARPOL Annex VI. Key measures within ECAs include: ■■ 1 August 2012: max 1% sulphur fuel is permissible ■■ January 2015: 0.1% sulphur fuel is permissible ■■ Scrubbing is allowed as an equivalent measure. The same applies to LNG fuel. ■■ Higher sulphur fuel can be burned if an equivalent emission reduction is obtained via scrubbers or other technologies.

››

LNG fuelling station.

other things, the presence of a Ship Energy Management Plan (SEEMP) on board. No changes were made to the SEEMP at MEPC 62. Regulations for diesel-electrical and steam-propelled ships were put on hold until a method of calculation can be developed. The following are applicable to OSVs: ■■ Ships with a diesel-electric, turbine or hybrid propulsion system will not be included before calculation methods are developed ■■ Reduction factors for small vessels are to be reviewed in 2013 ■■ There will be a review in 2015 based on technological developments, and this may lead to adjustments to dates and rates

In designing an energy-efficient OSV, four main areas need to be looked at: the hull, propulsion, machinery and other options. Hull solutions An optimised streamlined hull is one that is based on the most used speed and draft conditions. This, along with other features like flipper fins and bow forms, such as the wave-piercing type, needs to be verified by model testing and analyses. Placing the accommodation and superstructure aft as on the Viking Lady can be an obvious solution, as less displacement is required at the bow, allowing the implementation of finer hull lines. Another solution involves the use of retractable bow thrusters, which reduce drag. Another method is to install an air

Energy EfFIciency for OSVs

Photo: Per Sverre Wold-Hansen

generate electricity, they can contribute to reduce fuel consumption as only what is required is produced. Other fuel-saving features include waste heat recovery systems to feed into exhaust gas boilers, water makers and accommodation climate heating.

lubrication system. Air lubrication on the flat bottom plating using compressed air can reduce drag significantly. In addition, new hull forms to minimise the ballast requirement and thereby increase the cargo capacity are being considered. Propulsion systems Various configurations of propeller blades and types can add power savings of between two and eight per cent. The installation of nozzles and ducts, propeller boss cap fins, contrarotating propellers, a rudder-propeller transition bulb or rudder fins are some examples of this. Machinery choices In recent years, engine makers have carried out studies which have led to a number of innovative

designs. Diesel electric propulsion technology is continuing to evolve as the demand for more energy-efficient machinery increases. The easy integration of modern large-scale battery systems based on lithium technology makes it favourable and financially viable to install batteries on board. In relation to this, a new battery power class notation has just been developed by DNV. Another innovation, hybrid shaft generators, can be incorporated into the main and auxiliary engines. At cruising speeds, the hybrid shaft generators produce electricity for other consumers, while at slow speed they switch to become a motor powered by the auxiliary engine(s). Whether it is diesel or gas-powered, multiple or smaller capacity engine arrangements that

Other options Superstructures can be replaced by lighter materials such as fire-proof composite materials, saving as much as 50 per cent in weight and thus allowing more cargo-carrying capacity. Electric cranes and winches can replace hydraulic versions as they are typically 15 to 20 per cent more efficient as well as being less noisy and having lower pollution risks. When it comes to SEEMP, there are no quick-fixes, but a combination of a number of different measures can bring about significant results. These include weather routing, speed optimisation, auto pilot setting, engine monitoring, analysis of on-board energy consumers (operations relating to the cargo/crane, DP/ thruster, ventilation system /HVAC/lights, incineration), propeller polishing, hull coatings and cleaning, and fuel sampling. But it is not just technology or product analysis that needs consideration in light of SEEMP. Human interaction, such as improved cooperation between owners and charterers, crew competence and training measures are also vital, yet less often reflected upon. Conclusion As fuel prices soar, charterers are beginning to scout for energyefficiency-rated ships. Once delivered, hull forms are difficult to change. For the industry to stay ahead, yards need to start building more energy-efficient OSV hulls. Although EEDI and SEEMP may not immediately apply to small ships and ships on domestic trades, it is wise for a prudent owner or operator to look into these regulations when ordering new ships or operating existing ones. The benefits will be better and longer-term financial results, higher asset resale values and less air emissions. ď&#x201A;Ł

offshore UPDATE NO. 1 2012 |

Barents 2020 conclusive summary

Barents 2020 conclusive summary The Barents 2020 project commenced after the Norwegian Ministry of Foreign Affairs requested and funded a DNV-led effort to seek industry cooperation with Russia in order to harmonise and agree on HSE standards for use in the Barents Sea. It was understood that the Barents Sea represents new safety challenges for both Norway and Russia, and that Russian cold climate experience could fruitfully be merged with Norwegian offshore competence. TEXT: Leif Magne Nesheim, DNV

The premise of the project was that industry cooperation should look at technical standards which can be used internationally. Regulations and laws are national and outside the remit of this project. Phase 1 (October 2007–October 2008) produced five “Position Papers” and established the Norwegian-Russian partnership model for this project; DNV as the Norwegian/international project manager and Technical Committee 23 (VNIIGAZ/Gazprom) as the Russian project manager. This project management structure has been retained throughout the project. In Phase 2 (November 2008–March 2009), the financial industry sponsors selected from a range of topics and prioritised seven key areas to be examined in

44 | offshore UPDATE NO. 1 2012

further detail by seven specialist working groups. In this phase, the project participants agreed to use the existing safety level in the North Sea as a benchmark for the Barents Sea. Due to the more difficult consequence scenario – e.g. search, rescue and clean-up – the project concluded that an acceptable safety level could primarily be reached by reducing the probability of incidents and accidents. This confirmed the project’s focus on improving standards. The seven working groups in Phase 3 (May 2009–March 2010) focused on Barents Sea (i) common offshore standards, (ii) ice loads, (iii) risk management, (iv) escape, evacuation and rescue,

(v) working environment, (vi) loading/unloading and ship transportation, (vii) operational emissions and discharges to air and water. Their joint report was issued in March 2010 and included a list of 130 – mostly functional – standards recommended for common use. Many of the standards could be used in the Barents Sea without revisions, while several others needed revisions or further written guidance. This report – for Phase 4 (May 2010– March 2012) – is the final result of the Barents 2020 project. The industry sponsors – in phase 4 they were Gazprom, Stat oil, ENI, Total, OGP and DNV – agreed to bring forward from phase 3 those issues

Photo: Geostock/Photodisc/Getty Images

Barents 2020 conclusive summary

and topics that were in greatest need of completion, revision and detailed guidance. In phase 4, the project formally became international, although there had already been strong participation by international specialists in phase 3. These included French, American and Dutch specialists – just to mention a few. All in all, approximately 100 specialists from 40 organisations and companies participated in phase 4. The steering committee has consisted of the industry sponsors joined by ISO representatives Rosstandard of Russia and Standard Norge of Norway. The seven working groups from phase 3 were kept intact and continued their work with renewed tasks and mandates in phase 4.

Five of the seven groups (2, 4, 5, 6, and 7) were tasked with detailing and formulating recommendations to remedy the main deficiencies within their focus areas. These recommendations have been submitted – primarily ISO TC 67’s 19906 standard, and to the new TC67 Subcommittee 08, “Arctic Operations”. Independently of this, companies are free to use the deliverables as project-specific standards, and national standardisation bodies will also implement recommendations as they see fit. Group number 1 was tasked with recommending and guiding the process of formatting and channelling the deliverables and results to the correct standardisation addresses. Group number 3 – risk management – did not recommend any new standards,

and was tasked with running seminars with representatives from regulators and companies to exemplify through cases how risk management can be applied in cold climate field developments. The steering committee and plenum conference reviewed, commented on and approved the results in Moscow on 14–15 December 2011. This report documents the results and recommendations of all the working groups. It reads as a sequel to the phase 3 report (March 2010). To obtain full value of the results, both reports should thus be read. This is the final and conclusive deliverable from the Barents 2020 industry cooperation project. DNV and VNIIGAZ – as project managers – thus also conclude their work here. 

offshore UPDATE NO. 1 2012 |

Wellstream

Wellstream awarded DNVâ&#x20AC;&#x2122;s local content certiďŹ cation for Brazilian operations Expected investments in its oil and gas industry of approximately USD 400 billion over the next 10 years present Brazil with a unique opportunity to develop its local oil and gas expertise.

Photo: Getty Images

Text: Jose Pontes, DNV

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Wellstream

investments to increase its Brazilian manufacturing capabilities by 30% and build a new logistics centre at Niteroi.

Photo: DNV

Benefits for Brazil The views of Fernando Cruz, Wellstream’s Project Manager, reflect ANP’s goals. “The requirement of local content in materials and services contributes to technological developments in Brazil, promotes a more competitive supply chain both in Brazil and globally, and reduces the foreign dependence of the Brazilian oil and gas industry.”

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Fernando Cruz, Wellstream.

Local content requirements In fact, Brazil’s National Petroleum Agency (ANP) has recognised this opportunity and established standards for the local acquisition of goods and services. ANP also requires the local content to be verified by an independent third party, such as DNV, through a review of the documentation, measurement of the local content and issuance of Local Content Certification. Wellstream Wellstream do Brasil Indústria e Serviços Ltda, a part of GE Oil & Gas, is rapidly moving into deepwater production in Brazil, Africa and Asia with a complete portfolio of pipeline products, such as dynamic flexible risers, static flow lines and high temperature and pressure products for drilling and service applications. Wellstream began local production in its Niteroi, Brazil manufacturing facility in 2007 and has now committed to additional

The certification process Mr Cruz agrees it is necessary for an independent third party to assess and certify that local content requirements are satisfied. Wellstream initially had concerns that its proprietary or confidential data about its supply systems, manufacturing and assembly processes and even material invoices or import documents could enter the public domain. Now, he notes, “DNV’s integrity and full adherence to its confidentiality terms have led us to have full trust and confidence in DNV.” He hastens to add that “mapping local content from the documentation available, taking measurements and issuing certification were initially seen as a big challenge, but DNV was extremely helpful and gave us information about the local content regulations, providing practical training and efficient work processes.” Continuing development Mr Cruz notes that compliance with ANP’s local content regulations will be an ongoing activity. “Today, about 90% of the manufacturing and assembly is done in Brazil, but many of the raw materials are imported. For instance, some noble raw materials needed to manufacture flexible lines are only available outside Brazil. When raw materials are available locally, sometimes the cost is 10 times greater in Brazil. However, as local demand is stimulated, prices should drop and Brazil’s raw materials should also become competitive internationally.” DNV was accredited by ANP to issue Local Content Certificates in 2008. To date, DNV has issued more than 600 Local Content Certificates to domestic and international companies in Brazil. 

offshore UPDATE NO. 1 2012 |

Deepwater drives the development of new technology

Deepwater drives the development of new technology The limitations of today’s technology are being challenged as the oil and gas industry goes far offshore, into deeper waters and further into the crust of the Earth, to exploit oil and gas. New technology has to be developed and qualified to make these resources economically viable and ensure safe operations. Text: Hans Bratfos, DNV

the medium- and long-term challenges. Remoteness from shore and existing infrastructure challenge the logistics relating to both humans and hydrocarbons. Deeper waters and high well pressures demand new production systems for subsea processing, pipelines and risers. Developing riserless drilling is just one example of ambitious technology goals that make O&G one of the most exciting industries for engineers in the next few decades. 

Photo: BP p.l.c.

DeepStar’s next Phase XI programmes. Hydrate management, as opposed to hydrate avoidance, is an area of high attention. Some of the other focus areas are dry trees, mooring, VIV, new solutions relating to drilling & completions, subsea processing and reservoir technology. In Brazil, operators are required to invest 1% of their revenue in R&D, boosting technology development to prepare the O&G industry in Brazil to cope with

Photo: DNV

We can see fascinating developments driven by the deepwater fields in the outer GoM and West Africa and the Brazilian pre-salt fields. Mexico, India and China will also go in for deeper water prospects. Petrobras has ambitious plans for the presalt developments, involving short- and long-term goals along the whole production process, from reservoir to beach. To get an idea of what is on the GoM operators’ agendas, take a look at

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Hans Axel Bratfos, Directory of Technology, Services and Quality.

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Aerial of the Helix Q4000 taken shortly before “Static Kill” procedure began at MC 252 site in Gulf of Mexico, on 03 August 2010.

West African Gas Pipeline

West African Gas Pipeline The West African Gas Pipeline is an unusual example of cooperation in a difficult environment and on complex energy issues. Text: Peter Hamer, DNV

for the continued success of large projects in not only the established producing countries of Nigeria and Angola but also the emergent nations such as Ghana and the booming East African arena. Field lives are being continually extended beyond the planned life cycles and more complex analysis is being sought to provide confidence in these pipelines, which are revenue-critical assets. DNV Africa is now playing a strong role in providing local expertise with a global perspective and creating solutions on the ground with its local partners. 

Photo: Getty Images

(Ghana). The Escravos-Lagos pipeline system has a capacity of 800 MMscfd, and the WAGP system will initially carry a volume of 170MMscfd and peak over time at a capacity of 460MMscfd. DNV Ghana and DNV Capetown’s pipeline experts met with WAGPCo in 2011 and discussed the various operational challenges facing this multinational joint venture. DNV’s local expertise was able to help define the joint venture’s core pipeline risk management needs and subsequently worked with WAGPCo to develop its asset integrity management plan. The asset integrity management of pipelines in West Africa is a critical element

Photo: DNV

The West African Gas Pipeline Company (WAGPCo) is a joint venture consisting of national interests, with Nigeria, Ghana, Togo and Benin partnering with Chevron to create a viable energy solution so that Nigeria’s gas production can meet its neighbours growing energy demands. The 678km West African Gas Pipeline (WAGP) links up with the existing Escravos-Lagos pipeline at the Nigeria Gas Company’s Itoki natural gas export terminal in Nigeria and proceeds to a beachhead in Lagos. From there it moves offshore to Takoradi in Ghana, with gas delivery laterals from the main line extending to Cotonou (Benin), Lome (Togo) and Tema

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Peter Hamer, Director of Operations.

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Petrochemical processing equipment at oil refinery, Nigeria.

offshore UPDATE NO. 1 2012 |

Mooring Systems in Deepwater Fields

Mooring systems in deepwater ﬁelds What’s New in Moorings at DNV? DNV has been very active in mooring systems for both mobile drilling and floating production units (FPUs) since the 1970s, and continues to play a leading role in offshore moorings.

Photo: BP

Text: Vidar Åhjem and Robert Gordon, DNV

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Testing for BP’s Mad Dog project.

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Mooring Systems in Deepwater Fields

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Mooring Challenges and the Development Outlook As the demand for offshore production grows worldwide, the number of mooring systems in service is increasing. The average age of the worldwide fleet of Floating Production Units (FPUs) is also increasing. FPUs are now installed offshore on six continents, in climates ranging from tropical to polar. The water depth for new FPUs is continuing to increase, with Shell’s Perdido Spar now holding the world record for a permanently moored floating production system at 2,450 metres (8,000 feet). At this depth, mooring is made possible by the use of fibre ropes. Since starting to test very large fibre ropes for offshore mooring at its laboratory in Bergen, DNV has taken an active part in also developing this part of offshore mooring technology together with the industry. The laboratory was built to meet the testing needs of the Barracuda & Caratinga and Mad Dog projects in the early 2000s, with their respective 1,250-tonne and 1,932-tonne capacities. Later, DNV’s laboratory performed the mooring rope testing for the Cascade & Chinook project to verify compliance with DNV classification requirements.

Photo: Lankhorst

Mooring rope for the Cascade & Chinook project.

Setting standards In 2008, the Standard for Certification No. 2.13 was superseded by DNV-OS-E303 Offshore Mooring Fibre Ropes, which has served the industry ever since. The introduction of approval programmes for yarn and rope makers in Standard for Certification No. 2.9 in 2010 helped standardise the documentation processes, and currently work is ongoing to refine and complement the documents available to the industry. Getting Older – Mooring Integrity Management As FPUs grow older, managing the degradation of moorings is becoming increasingly important. Although degradation over time is considered during the design phase, it is

important to keep it at a minimum and even be able to extend the service life of installations. Wear, corrosion and fatigue are the primary sources of degradation, and must be managed in the same way as operating costs. DNV is helping the industry by developing guidelines for risk-based mooring integrity management. Once completed, these guidelines will allow the efficient and effective inspection of mooring systems.

NorMoor – Revised Safety Factors for Mooring Line Design The objective of the ongoing NorMoor JIP is to calibrate safety factors for mooring line design so that they provide the target reliability. The initial work is looking at the Ultimate Limit State (ULS). Additional phases may consider accidental and fatigue limit states. Fibre Rope Technology Defines the Future of Moorings As FPU water depths increase, the need for strong, lightweight synthetic mooring ropes is also increasing. Deepwater moorings (more than about 1,000 meters or 3,000 feet) around the world now rely on polyester mooring ropes. An important topic for the future is

offshore UPDATE NO. 1 2012 |

Mooring Systems in Deepwater Fields

the definition, measurement and expression of fibre-rope change-in-length characteristics. This is an area which the industry has been grappling with for the past 15 years or more due to the non-linear, visco-elastic behaviour of synthetic mooring lines. A major milestone in this process was the definition of the analogue model (Flory) in a comprehensive Joint Industry Project in which DNV cooperated with key members of the industry. The analogue model provides an illustration of rope responses to changes in tension, making it much easier to understand the way the rope behaves. /1/ The mechanical properties of the fibre rope are what will drive the behaviour of deepwater mooring systems. This means that it is the axial properties and length of the rope that govern the mooring system restoring forces and platform offset, and the fatigue loading of connected steel components. Hence, the focus must be on a design that balances strength with change-in-length and fatigue resistance; oversizing the rope will reduce the fatigue design margins.

Photo: DNV

SyRope – Global Performance of Synthetic Rope Mooring Thus, it is essential to characterise the nonlinear tensionelongation behaviour of the mooring system as a whole. As Kjell Larsen of Statoil explains: “Applying the exact physical behaviour of fibre rope in offshore mooring analyses is extremely important to deepwater field development; and with the on›› Test machine The Bristle Worm. going SyRope pilot studies implemented for polyester we will also be able to harness the potential predicting the global performance of synthetic rope moorof using other synthetic materials if needed.” ings and should be able to bring the analysis models for As a result of these needs, Statoil, DNV and SINTEF fibre rope systems to a mature level. This JIP will include Marintek are co-operating closely to develop the new gensynthetic-rope testing, the development of advanced eration of mooring design software algorithms for synthetic numerical mooring models, case studies and the develmoorings. /2/ This project is called SyRope and Statoil has opment of an analysis guideline for fibre rope mooring already implemented “best design practice” as a result of systems. the pilot project findings. The pilot study will be completed As shown in Figure 1, in the traditional catenary moorduring the spring of 2012, and a follow-up Joint Industry ing system, the weight and geometric stiffness of the moorProject will be launched in 2012. ing system provide the main stiffness characteristics. In The SyRope JIP will develop improved algorithms for

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Mooring Systems in Deepwater Fields

the taut system (bottom/left), the axial properties of the ropes alone determine the station-keeping performance, including the wave-driven fatigue loading. The objective is to establish the SyRope design methods as industry best practice within the next few years, and to make the use of synthetic fibre moorings even more viable, efficiency enhancing and profitable than it is today. 

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Catenary mooring.

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Taut mooring.

/1/Flory, Åhjem, and Banfield ‘A New Method of Testing for Change-in-Length Properties Of Large Fiber Rope Deepwater Mooring Lines’, OTC 18770, May 2007. /2/Falkenberg, Åhjem, Larsen, Lie and Kaasen ‘Global Performance of Synthetic Rope Mooring Systems – Frequency Domain Analysis’, OMAE2011-49723, June 2011.

offshore UPDATE NO. 1 2012 |

Hushing Underwater Noise

Hushing underwater noise Think of a large city. Think of the noises you can hear. Do you think it was always this noisy? Now, think of our oceans. Think of the noises you can hear. You may not hear them, but if you wonder whether our oceans are becoming as noisy as a big city, then you are not alone. Text: Blaine Collins, DNV

Concerns Marine mammals such as whales and dolphins rely on sound to communicate with each other, locate prey and find their way over long distances. Underwater noise from ships, sonar devices and exploration activities interfere with their ability to communicate, navigate and feed themselves. Understandably, national authorities are concerned that underwater noise from ships, offshore vessels and drilling activities may have a negative impact on marine mammals and fish. The International Maritime Organization (IMO) also has regulations for underwater noise on its development list and the Arctic nations will undoubtedly be especially concerned about underwater noise in the High North. Ship owners and fishermen are concerned that underwater noise may affect the operating capabilities of their vessels. Noise can scare fish or hinder the operations of a survey, seismic or research vessel. Solutions DNV’s voluntary class notation, SILENT, is the first set of rules for underwater noise emissions from vessels. SILENT is based on DNV’s years of experience in underwater noise control, vibrations and measurements. The SILENT class notation addresses two issues. Firstly, it provides the owners of acoustically sensitive vessels with precise and realistic criteria to minimise noise emissions into the water. Secondly, it offers national authorities a third-party, independent standard to adopt as national regulations or incorporate by reference.

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Photo: DNV

Today, underwater noise is a growing concern for national authorities, sovereign states, ship owners and operators, fisheries, designers and the public.

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Blaine Collins, Director Divisional Staff, Division Americas.

In addition to the SILENT class notation, DNV also provides advisory services to owners, designers and shipyards to ensure that their designs have low-noise features. However, noise control is not a purely theoretical subject. Practical follow-up during the building phase is very important for noise-critical projects to ensure that all the necessary details are correctly included. An extensive noise-control effort may be severely degraded by minor mistakes or “short-cuts” taken during the construction phase. In case you missed it before, you have now “heard” about DNV’s SILENT class. 

Hushing Underwater Noise

Photo: iStock

Marine mammals such as whales and dolphins rely on sound to communicate with each other, locate prey and find their way over long distances. Underwater noise from ships, sonar devices and exploration activities interfere with their ability to communicate, navigate and feed themselves.

offshore UPDATE NO. 1 2012 |

Maintenance

Maintenance of mobile offshore units and floating structures

– it’s only getting better Sixty per cent of the world’s offshore fleet is past its theoretical design age of 20 years. Rigs and production platforms are being kept in operation for prolonged periods, well beyond their anticipated design life. Text: Michiel van der Geest, DNV

As a class society, one of DNV’s key services is helping owners to ensure the reliability and safety of their assets by providing them with effective and efficient maintenance methodologies and techniques. Indeed, DNV has recently published two new Recommended Practices (RP) for bonded repairs of steel structures and lowering maintenance and/or inspection costs. DNV-RP-C301, Recommended Practice for the Design, Fabrication, Operation and Qualification of Bonded Repairs of Steel Structures Welded repairs of floating structures can become extremely costly as hot-work may lead to shutdowns and considerable loss of revenue. This has led to increasing interest in using cold repair methods. To develop guidelines for bonded patch repairs of FPSO structures, DNV launched a Joint Industry Project which led to DNV’s recommended practice for bonded repairs. This approach allows considerable cost savings and the minimum interruption to operations. The principle of a bonded repair is shown in Figure 1. The structure was designed for certain loads, but has to be repaired once fatigue or corrosion damage reduces its capability and strength. Instead of welding, with the hot-work issues involved, a stiff and strong patch is bonded onto the structure to restore its integrity. DNV’s RP provides guidance on the cold repair of non-critical defects and the installation of secondary structures, as well as criticality assessments of defects,

56 | offshore UPDATE NO. 1 2012

the design of a patch, qualification of materials and patches, fabrication on site and final inspection. Additionally, the RP provides a method to predict the capacity of bonded patches. One example of a bonded repair is shown in Figure 2. DNV-RP-C302, Risk-Based Corrosion Management This is a holistic approach to assist owners in lowering corrective maintenance inspection costs. Unlike traditional planned inspections and reactive corrective maintenance, the DNV RP approach provides tools for a quantitative comparison of corrosion damage and required remediation, as well as clear communication of the damage and repairs to the owner’s management. A key advantage of this approach is that it can be applied generally or with different levels of implementation without losing its practicability and effectiveness. It can be used for units ranging from those under construction to older units, from units in benign waters to units in harsh conditions, from inspections based on existing information to complete and extensive analyses.

With these two RPs, DNV has introduced two practical tools; one targeting technical aspects, bonded repairs, and the other guiding the implementation of management systems for corrosion control. Together, these two tools support a reduction in overall maintenance and repair costs. 

Maintenance

Establishing the Context

Step 1

Step 2

Risk Ranking Risk Analysis Step 3

Risk Evaluation

Detail Evaluation

Step 5

RISK ASSESSMENT

Risk Identification

Life Cycle Management

Monitoring and Review

Risk Assessment

Step 4

Risk Treatment

Figure 1: Concept of the bonded patch repair for cracks and corrosion.

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Figure 2: The standard process as described by ISO-31000, Risk Management, on the left, and the practical approach of DNV’s RP on the right.

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Remediation & Repair

offshore UPDATE NO. 1 2012 |

DNV Houston

DNV Houston shows software integrity DNV has a long history of working with software-dependent systems across a range of industries, including automotive, telecom and aerospace. In 2008, DNV released a Recommended Practice for Integrated Software Dependent Systems (DNV-RP-D201). Text: Richie Mactaggart

The ISDS methodology has been built on DNV’s decades of experience in addressing the software integrity of embedded systems, and the methodology represents the industry’s most comprehensive and effective software-related risk management tool to date. After piloting ISDS in more than 10 offshore projects, the Recommended Practice was promoted to a tentative Offshore Standard in 2010 (DNV-OS-D203). In 2011, the Offshore Standard and associated class notation were released in their final version, ready to be applied in projects worldwide. ISDS can be applicable to any parts of the hydrocarbon chain and is finding favour among energy companies in the Gulf of Mexico. It is a collection of best practices for software developers in oil and gas, service and dedicated software companies. Its popularity is growing as the industry shifts from mechanically orientated to software-managed solutions. Allen Prescott, PMP and CSQE Senior Consultant, DNV, Houston, says: “ISDS comprises a week-long assessment. During this time DNV, looks at all the processes and procedures of a software development company or department and creates a gap analysis. DNV shows the documentation created during the product development process, such as work instructions. Best practice documentation also needs to be full and complete – along with whether employees are following procedures. We

58 | offshore UPDATE NO. 1 2012

are now seeing rig owners ask for software to be ISDS compliant and this is often specified in tender documents.” The use of ISDS enables developers to find bugs more easily. ISDS-compliant processes ensure that software is tested correctly because they create mapping and traceability and set out methods to ensure that requirements are being implemented. It was actually the industry that asked for these procedures to be in place. More rigs and other systems are now utilising software and other electrical controls, so operators began requesting ISDS. DNV’s Houston office is concentrating on two services: Pre-qualification: whereby DNV looks at how companies are developing products and how capable these products are of being compliant with ISDS. There are a lot of process models, along with ISO standards, and this has become a subset of best practices. The capability maturity model, for example, is a qualification procedure for companies that have large programming and developing departments. However, this was too extensive for most development departments in the oil & gas industry and ISDS is seen as being more applicable to them – particularly for analysing safety and uptime processes. Classification: when ISDS is added to a new build and filters down to suppliers, they have to be compliant with ISDS

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DNV Houston office.

requirements. DNV is more involved in the verification process. For example, a new rig owner can specify that it wants all software to be ISDS compliant throughout the product supply chain. Out of Houston, DNV has recently completed one pre-qualification of a large supplier of various components for offshore products. A final letter of compliance is valid for one year. If the supplier does not participate in a new class project, it will need to re-qualify. Otherwise, if it has

Photo: DNV/Per Sverre Wold-Hansen

DNV Houston

participated within that time period, it just has to show the client its qualification. The biggest benefit of ISDS is that it looks at procedures up-front – at which point it is easier to make software fixes. For example, the developer can ask someone to look at the code that has been written and this will be a much easier process if a company has ISDS documentation. DNV would like to see ISDS become an integral part of the software development process.

Prescott concludes: “I am excited about this service and like going into companies explaining the benefits that ISDS can give them. We’re trying to get them to take advantage of the software development best practices. Mechanical engineering has been around for 80 years, but software is new to them. We are now starting to see a push from the yards for the pre-compliance of products as this simplifies the tendering and purchasing process.”

The bottom line is how much pain would an operator experience if software fails? If a bug causes a rig to be shut down for a day, this can be a massive cost – possibly hundreds of thousands of dollars. Spend a little money up-front and it can be saved down the line if processes and management are in place. Maybe the question should be whether any software should be used in the oil & gas industry if it is not ISDS compliant? 

offshore UPDATE NO. 1 2012 |

Synergi

Synergi looks to Asia and the Americas DNV Software is significantly expanding the sales of its Synergi software, with an added focus on the markets in the Americas and Asia after the softwareâ&#x20AC;&#x2122;s success in Europe. Although this expansive strategy was implemented as recently as in January of this year, Synergi has already landed some major contracts in North America. Text: Kaia Means

Photo: iStockphoto

DNV Software DNV Software is a leading provider of software for managing risk in the energy, process and maritime industries â&#x20AC;&#x201C; offering solutions for design, engineering, strength assessment, risk and reliability, QHSE and asset integrity management. DNV Software is part of DNV and almost 300 DNV offices in 100 countries enable us to be close to our customers and share best practices and quality standards worldwide.

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Synergi

Synergi Synergi is a complete and user-friendly solution that manages all non-conformities, incidents, risks, risk analyses, audits, assessments and improvement suggestions. It covers every workflow process, such as reporting, processing, analysing, corrective actions, communication, experience transfer, trending and KPI monitoring.

Photo: iStock

Synergi eases communication and cooperation throughout the organisation, leading to increased efficiency and improved QHSE performance. Synergi has multi-language capabilities and reporting is intuitive and self-instructive. Lessons learned are shared, and repeat errors are prevented.

Two major signings are just the start of Synergi’s push into the Americas and Asian markets with its risk and QHSE management solution. In March, two new major Synergi contracts were signed in North America. The first was with Canada’s Talisman Energy, which is based in Calgary. Talisman will be rolling Synergi out to all business units worldwide. The second was with Houstonbased Marathon Oil Corporation, where a local Synergi live trial last year will now be replaced by a corporate platform physically placed in Houston but for global use. By 2013, a full 4,000 Marathon Oil professionals will be using the system in four different languages, trusting Synergi and DNV to strengthen their operational integrity. HESS Corp. is moving on to the latest version and expanding its use of Synergi to include the advanced Synergi® Risk Management™ module. Recently it became clear that ENSCO is also looking to expand its use of Synergi in 2012. When DNV Software acquired Synergi in May last year, the new management team immediately started implementing a strategy to increase Synergi’s global p resence, relying on DNV’s current footprint of nearly 300 offices in 100 countries.

Synergi is building on its market-leading position in Europe and beyond within the oil & gas sector. Some 80 per cent of the major oil & gas players in the North Sea rely on Synergi for operational risk and QHSE management. The Synergi brand is extremely strong in Europe and, with the help of the worldwide DNV network, opportunities are growing. “We have an exciting few years ahead of us,” says Principal Regional Sales Manager Stein Olav Skarbø. “We firmly believe that in the Americas, the world’s single largest economy, there is an opportunity to support larger organisations that have the necessary maturity to implement Synergi,” he says. “US and Canadian companies’ strategies in particular are becoming more long-term, especially within the oil & gas industry. In DNV Software, our focus is on long-term strategy, stability and integrity, facilitated by acknowledged tools like Synergi. The American market is absolutely ready for this, and Synergi is certainly fit for purpose,” says Skarbø. DNV Software’s Regional Director for the Americas, Mike Johnson, says the market is speaking clearly. “When you consider our advisory services, investment in local support, and DNV Software’s nearly 50 years of credibility, you have an

Based on the analysis of statistics and reported incidents, managers can confidently suggest and implement actions, ensuring a secure workplace in many different industries, such as health care, petrochemical, maritime, transport and oil & gas.

unmatched combination for delivering customer value,” he says. “The partnering of Synergi with our Safeti risk and reliability tools and services gives our customers insight into the detailed aspects of process safety while creating decision-ready metrics from varied and disconnected data sources.” Business Development Manager Gisle Bråstein is responsible for operations in Asia, the Middle East and India. Since starting sales work in January, he has already signed some contracts and expects some larger contracts in China, Malaysia and the Middle East to be finalised in the second quarter of the year. “This is a large region with many opportunities,” he says. “We’re in contact with several state-owned energy companies in China and India. They’ve had success in their domestic markets, and want to take a step forward towards the international markets. But this means more competition, in addition to stricter regulations. These companies in growing economies are looking to successful European companies to learn from such companies’ experience and to see how they can improve. They understand that European companies have found Synergi to be important for achieving success in QHSE management,” says Bråstein. 

offshore UPDATE NO. 1 2012 |

PERTAMINA

Pertamina: going for “world class” by 2014 The business culture and business model, etc, of Indonesian state oil company, Pertamina, have undergone, and are still undergoing, major transformations. This also includes numerous considerations relating to HSEQ issues. Text: Eric Kaljo Roos, DNV

In line with the above, Pertamina’s Exploration and Production Division (PEP) has launched an initiative to make its HSEQ practices “world class” by 2014 and, to do so, has chosen to use DNV’s ISRS – International Sustainability Rating System, 7th edition, as its main management system implementation, measurement and assessment tool. As a brief aside, the selection of and reason for choosing ISRS followed on from PEP’s interaction and benchmarking with PT Badak NGL in Bontang, East Kalimantan, Indonesia – which is another well-established ISRS user since 2005 and is currently at level 8, using the 8th edition of ISRS. Another key driver was Pertamina’s Chief Director, Ms Karen Agustiawan, and her recommendation to go with ISRS in Pertamina Exploration and Production as well as in other Pertamina units – such as PertaGas, Pertamina Drilling, Pertamina Marketing, etc. This internal PEP initiative was officially launched in 2006. DNV started working with Pertamina, using ISRS to support this initiative, in 2010, and this work will ultimately cover around fourteen of PEP’s exploration and production sites/concessions throughout Indonesia. The general

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stages to achieve ‘world class’ are presented in PEP’s graphics below. Indonesia has been spearheading this project, and has achieved excellent project management results to date. This work has been led by DNV HSE consultants Mr Ferry Sonnevil and Ms Rimalia Sebayang. From the PEP side, DNV has enjoyed excellent coordination and cooperation with Mr Djoko Susanto, PEP Corporate HSE Manager, and Mr Chairul Soeeb, the ISRS project coordinator responsible for helping to schedule training, assessments and other related services with DNV. Currently, DNV Energy Indonesia is helping PEP on the ISRS journey at six sites: PEP Subang and PEP Tambun in West Java province, UBEP Tanjung in South Kalimantan province, PEP Rantau in North Sumatra province, PEP Limau in South Sumatra province and UBEP Jambi in Jambi province. These journeys include the full range of ISRS services, typically beginning with an ISRS alpha assessment, msm2 training, ISRS assessor training, ISRS assessments and other training, such as professional event investigation, as well as facilitation man-days to help PEP develop management systems.

PERTAMINA

Transformation of PT Pertamina EP Grand strategy “First quality, then growth, then strive for excellence”

Values: Sincere, strong & Sensible

VISION 2014 PEP world class

VISION 2011 To be the number one oil & gas producer in Indonesia

VISION 2008 Respectable, cost-effective & efficient oil & gas producer

Photo: DNV/Erik Kaljo Roos

STARTING IN 2006

DNV HSE consultant Ferry Sonnevil.

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Mission: To carry out oil & gas activities in the upstream sector while applying the principles of environmentally friendly, health and safety, and to create excellence and added value for our stakeholders

Pertamina Exploration and Production’s overall roadmap for “world class” Excellence by 2014.

Photo: DNV/Erik Kaljo Roos

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Implementing Good Corporate Governance. Health, safety and environmental excellence

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DNV ISRS assessor Ferry Sonnevil (white helmet) conducting the ISRS physical conditions tour at Pertamina Tambun field.

In addition to Pertamina Exploration and Production, another Division of Pertamina, Pertamina Gas (‘PertaGas’), has also embarked on the same ISRS journey. This division is responsible for gas transport activities and manages hundreds of kilometres of gas pipeline networks on several of Indonesia’s largest islands, such as Java, Sumatra and Kalimantan (or Borneo). To date, five ISRS 7th edition alpha assessments have been conducted for the five PertaGas assets/sites, and the next stages of the journey are being coplanned with DNV, once again, to include numerous training courses such as msm2, ISRS assessor training and executive presentations for senior PertaGas leaders, as well as full ISRS assessments later in the year. As a result of all this ongoing activity, at least two notable achievements and benefits have accrued to DNV Energy and DNV Energy Indonesia: 1) DNV Energy’s overall strategy of working with national energy companies is now well entrenched in Indonesia, and… 2) DNV Energy Indonesia’s ISRS activities have catapulted the company into the number one category for ISRS revenue in 2012. 

offshore UPDATE NO. 1 2012 |

Observations of Onshore Pipeline Regulatory Trends

Observations of onshore pipeline regulatory trends Anything to learn for an offshore operator? A decade has passed since the Pipeline Safety Act of 2002 was passed by the US Congress. With stiffer regulations pending for the offshore pipeline industry, what can offshore operators learn from their onshore counterparts’ experiences? Text: Chris Pollard, DNV

In the case of onshore pipelines, a few notable incidents at the turn of this century brought pipeline safety into the public spotlight and resulted in a series of reactive, mostly prescriptive measures to improve pipeline integrity management. Similarly, offshore operations (pipeline or otherwise) now face a new degree of scrutiny also due to a few recent, highly visible incidents. One might argue that there is a huge difference between onshore pipeline operations and the vast domain of offshore operations. Though literally true, the various sectors are often seen as a single entity by a cynical public – all with the help of media headlines and a 24-hour news cycle. It may be helpful for US offshore operators to study the effects of onshore pipeline failures on subsequent reactive legislation. These effects are illustrated by the Code of Federal Regulations (CFR) Parts 195 (liquids) and 192, Sub-part ‘O’ (gas). Through Integrity Management Programme (IMP) ‘rules’, the DOT directs pipeline operators to establish and follow a detailed IMP. The main elements of the rules are briefly as follows. Risk Assessment Federal regulations now require a formalised risk assessment as part of an overall IMP for ‘High Consequence Areas’ (HCAs) that would, were

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they to fail, have significant adverse effects on population, property or the environment. The first phase of the completed IMP rules called for identifying HCAs and corresponding threats and establishing integrity assessment timetables. Integrity Assessment Some view the overall rules as an integrity assessment regulation. This part of the IMP rules calls for the establishment of HCA baseline assessments followed by assessments at regular, prescribed intervals. The assessments are to be aimed at those specific risk factors identified as affecting the integrity of the HCA segment. Acceptable assessment methods include in-line inspections (ILI), pressure tests, direct assessments, or the use of other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe. Onshore operators encountered considerable problems in making their lines piggable for ILI. However, most of the time, their biggest problems merely involved the installation of traps. Indeed, onshore pigging issues pale in comparison to offshore challenges: e.g. space limitations, heavy walls, unpiggable connections, extreme geometry and complex operations. Considerable capital outlays can be anticipated if lines are to be made piggable.

Repair/Mitigation The rules prescribe a timetable for addressing integrity-affecting anomalies depending on their severity or proximity to pipeline features or interacting defects (i.e. deformation near seam welds, mechanical damage). Documentation Though much emphasis is placed on integrity assessment, this is only part of a grander vision to improve overall pipeline safety by ensuring that all the data is accurate, verifiable and complete. It should be noted that some onshore efforts are further hampered by an issue that is not so common offshore: vintage pipelines. Some US in-service pipeline assets are many decades old, built using early construction methods and materials – with as-built records often inaccurate or missing entirely. A recent, very visible natural gas pipeline failure in San Bruno, CA illustrates the danger of insufficient records: the operator experienced a long weld seam failure when records stated that seamless pipe had been installed. With the attention that San Bruno brought to material properties and their documentation, new measures are under way to ensure that the maximum allowable operating pressure (MAOP) and supporting documentation can be properly verified.

Observations of Onshore Pipeline Regulatory Trends

Interdependent Threats A driving force for proper data integration can be found in the new focus being placed on interacting or interdependent threats. More in-depth considerations relating to such threats are currently pending action by regulators and the industry.

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Continuous Improvement Although onshore pipeline failure statistics appear to be improving, the industry still seems to be experiencing significant and unexpected catastrophic events that no one, including the operator, wants ever to happen. Such events have been termed by DNV’s subject matter experts (SMEs) as occurring within ‘super HCAs’: highly sensitive pipe segments where the occurrence of a failure might ultimately bankrupt the operating company. Some thought the loss of the Deepwater Horizon in April 2010 had the potential to fit that category. The continuous improvement and management of change methodologies are helping to recognise those pipeline segments and minimise the probability of such an occurrence.

Onshore ILI Pig Launch.

Going Forward The pipeline failures listed here, and others, have forced industry regulators to take a stronger stance, as evidenced by new IM rules, the elimination of some grandfathered exemptions, the requirement of records not previously required, etc. No one will disagree that offshore operations face similar challenges and more. Certainly, many of the same factors profoundly affecting regulatory change in onshore pipelines now exist in the offshore environment as well.

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‘Pipeline Tee’ incorrectly identified by ILI.

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Chris Pollard, Principal Consultant.

Are there lessons to be learned? DNV is a logical choice for integrity needs, both offshore and onshore. DNV’s pipeline business unit has been involved in the post-failure response to virtually every major US pipeline failure over the past quarter of a century. Grounded in the applied science of our research laboratories, we have the depth and breadth of subject matter expertise to cover the entire spectrum of materials research, testing and degradation, mechanical integrity and risk management. 

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Integration/Reconciliation Not far down the Potomac from Washington, D.C. is Piney Point, MD. On 7 April 2000, a fuel oil pipeline ruptured, spilling approximately 140,400 gallons of fuel oil into the local wetlands, and this fuel oil eventually made its way into the Patuxent River and caused damage costing over USD 71 million to repair. The incident illustrates one reason why integration was a hot topic when current onshore regulations were being prepared. In that instance, an ILI mistakenly identified a harmless ’tee’ before the rupture correctly revealed that the ‘tee’ indication was actually a buckle (with a resulting fracture). In another landmark liquid product pipeline failure, NTSB investigators found that the operator had misinterpreted ILI data. Had an ILI been fully reconciled with right-of-way activity, it would have revealed with higher certainty that the ILI anomalies were in fact mechanical damage as a result of adjacent municipal construction. This failure, which took place on 10 June 1999 in Bellingham, WA, resulted in the ignition of a creek, took three lives and caused over USD 45 million in property damage. Few if any other single incidents have had more impact on US pipeline safety regulations than this one in Bellingham. These not-so-happy integration stories can be countered with a happy one from one GoM operator. When ILI identified a harmless ‘bend’ that the operator knew did not exist, the ‘bend’ in question turned out to be a profound, integrityaffecting buckle. This operator’s timely and proper reconciliation of data helped to avoid imminent subsea failure. Indeed, there are many ILI success stories that can be chronicled to counter some of the notso-flattering ILI examples.

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Oil spill

Oil spill risk management The offshore industry invests considerably in safety and environmental protection. These investments have resulted in a steady improvement in safety and environmental performance. Despite this – accidents and accidental oil spills still happen.

One of the challenges when it comes to managing the risk of major accidents, such as large oil spills, is that the incidents are unlikely, although the potential impact is high. Examples include: Montara, Macondo, Bohai Bay and Frade. These are low probability – high consequence incidents (Montara, Macondo) and higher probability – lower consequence incidents. However, they all have potentially high consequences with respect to cost and reputation. In order to manage the oil spill risk properly, it is important to understand all aspects of the risk; from the reservoir conditions that can increase the risk, via controlling measures, like a blowout preventer (BOP), that can reduce the risk, through the fate, dispersion and drift of oil in the water column and at the sea surface, all the way to the area’s environmental sensitivity and the risk of environmental and socioeconomic impacts. The oil industry is searching for a way to improve oil spill risk management and methodologies for analysing the oil spill risk as well as the effect of risk reduction. They are looking into how a risk/hazard based approach can improve oil spill prevention and mitigation. Oil spill risk – “from the well to the shoreline” Traditional oil spill risk management is segmented into various disciplines, such as drilling, well

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Text: Ole Øystein Aspholm, DNV

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Ole Øystein Aspholm, Senior Principal Consultant.

control and oil spill response preparedness. The oil spill risk level is influenced by the reservoir conditions all the way from the well to the drilling rig and by the sensitivity of the ambient environment in which the operation takes place. There are a lot of external risk parameters that we cannot change, like the reservoir conditions, fluid type, weather conditions and occurrence of sensitive environmental resources. But the risk can be controlled by using preventive and mitigating measures. The risk of these measures failing is also part of the oil spill risk picture and thus an important part of the integrated oil spill risk management. This includes oil spill preventive measures in the well design and drilling operations as well as oil spill response and recovery measures.

DNV project/approach to ensure integrated oil spill risk management DNV has developed and applies oil spill risk management methods and techniques that cover all aspects of the risk of major oil spill accidents – from the well to the shoreline. Reservoir and operation-specific parameters are taken into consideration when calculating the blowout/leakage risk in terms of the probability of a blowout or leak occurring, the fluid characteristics and the flow rate and duration of the blowout/leak. In order to control and manage the risk, all potential blowout/leak scenarios must be considered, not only the worst-case blowout. DNV takes a multidisciplinary approach to assessing the drilling or well operations, based on a set of predefined criteria for assessing the probability of a leak or a blowout. Well flow simulations are used and adjusted in order to assess the wellspecific leak and blowout rates for the different operations. The potential leak and blowout durations are calculated using statistical models and taking into account the context of the drilling and well operations. This approach takes into consideration the field-specific reservoir challenges and the reliability of the oil spill prevention measures and technology, such as the BOP. One of the challenges is to quantify the human factors that influence well control. However, combining statistical blowout

Oil spill

data with the technology-reliability data and risk of failure due to human factors gives an important understanding of the robustness of the oil spill preventive measures. The results are more accurate risk predictions and a better understanding of where to improve or add barriers and control measures. Understanding the risk of a major oil leak or a blowout gives half the oil spill risk picture. The probability of impacting personnel and the environment and the potential consequences of this must also be included in the overall risk picture. DNV applies a state-of-the art oil drift modelling tool OSCAR (from SINTEF) to model the dispersion and drift of oil. The simulations give a misbalance of the oil in the water column, at the sea surface, at the shoreline and in the sediment as well as percentage evaporated and degraded oil compounds. The oil drift modelling results are combined with data on the abundance and distribution of environmentally sensitive resources and the sensitivity ranking of the resources. This shows the potential environmental impact of an oil spill. The risk is calculated by combining the potential impact with the probability of the spill and the probability of oil pollution of the sensitive environmental resources. However, oil spill risk management is about more than just preventing oil spills and understanding the potential impacts

of a spill. Mitigating measures, such as oil spill detection, oil spill recovery and source control, are an important part of oil spill risk management. The oil spill response mainly has five options; well kill (ultimately by drilling a relief well), subsea capping and containment, containment of oil at the sea surface with either in-situ burning or mechanical recovery, chemical dispersion of the oil plume at the seabed or of the oil slicks at the sea surface. The last option is shoreline cleaning and wildlife rescue if the other measures fail to stop oil from polluting a shoreline or animals. Oil spill response is a complex operation and it takes good planning to achieve an efficient and effective oil spill response. This planning is expressed in the operators’ and authorities’ oil spill contingency plans. Bringing in the various options for oil spill detection and oil spill surveillance makes the picture even more complex. So how is an operator to make the right decisions in order to develop an oil spill contingency plan that takes the operations’ oil spill risk into account? To ensure that the oil spill response level is connected to the level of risk, a detailed oil spill contingency analysis (OSCA) is carried out in conjunction with an environmental risk assessment (ERA). The methodology includes estimating the Effective Daily Recovery Capacity (EDRC) based on relevant wind, wave and current

conditions, as well as the efficiency of dispersant use. The total efficiency of the oil spill response is modelled and evaluated with respect to the oil spill’s environmental risk. The oil companies’ challenge is to be able to understand the risk level, to define not only the probability of a blowout and the worst case scenario, but also more likely spill scenarios and the potential environmental impact of all the spill scenarios. Further, it is a challenge to estimate the oil spill response needed to sufficiently handle the potential oil spills. An integrated oil spill risk management tool that takes into account the environmental risk level and effect of preventive measures as well as the effect of mitigating measures, such as oil spill detection and oil spill response, will be a helpful tool for the operators to better manage the oil spill risk. DNV’s experience of oil spill/environmental risk assessment is that it is very complex and often not connected to the decision-making regarding risk reducing measures – both preventive and mitigating. By making a tighter connection between the elements, we will be able to assess/ rank the risk level of various operations, including the risk reducing measures. This will give the operator a tool for understanding and evaluating the risk level and for considering whether there is a need for further risk reducing measures. 

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Offshore safety

Making SEMS – enhancing offshore safety in North America Following the Macondo incident in the Gulf of Mexico in April 2010, the US authorities determined that there was a need for further regulations aimed at enhancing safety and environmental standards. This resulted in the quick promulgation of SEMS regulations – a systematic approach to managing offshore safety. Text: Richie Mactaggart

In November 2011, the new Safety and Environmental Management Systems (SEMS) regulations came into force on the US outer continental shelf (OCS). Managed under the auspices of the Bureau of Ocean Energy Management (BOEM) and Bureau of Safety and Environmental Enforcement (BSEE), the new requirements are intended to enhance offshore safety and environmental standards. As it now stands, SEMS’ latest iteration requirements are the result of a succession of developments to extend the regulations applicable to the US offshore industry. BOEM and BSEE were created in October 2011 out of an earlier organisation, BOEMRE. This organisation’s predecessor, the Minerals Management Services (MMS), originally introduced SEMS as a recommended practice for operators back in 1990. Following this, in 1994, MMS endorsed the American Petroleum Institute RP 75, Recommended Practice for the Development of a Safety and Environmental Management Program for Offshore Operations and Facilities. RP 75 was updated in July 1998 to focus more

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on contract operations, including operations on mobile offshore drilling units. The major difference in SEMS now is that it is mandatory, rather than optional, as it was before. These new regulations require offshore operators to maintain comprehensive safety and environmental programmes to strengthen operational safety and reduce the risk of human error. As part of the new requirements, all operators are required to develop, implement and maintain a SEMS programme. Cheryl Stahl, Head of HSE, Risk Management Solutions, DNV Houston, states: “SEMS is a requirement that, in general, requires offshore operators to have certain documentation and define roles and responsibilities. DNV intends to become an approved third-party auditor for SEMS. In addition, during a SEMS audit, DNV can gather additional information and highlight potential areas for improvement.” DNV can provide benchmarking in addition to the SEMS audit services, adding value to what will eventually become a routine service.

The role of SEMS According to BSEE, the four primary SEMS objectives are to: ■■ Focus attention on the influences and effects that human error and poor organisation have on accidents; ■■ Continuously improve the offshore industry’s safety and environmental records; ■■ Encourage the use of performancebased operating practices; and ■■ Collaborate with industry in efforts that promote the public interests of offshore worker safety and environmental protection.

BSEE also states that SEMS is a regulation for coordinating offshore continental shelf (OCS) oil and gas operations in relation to worker safety and pollution control. BSEE has determined that OCS operators must use SEMS as the foundation for the way they undertake their offshore business. SEMS regulations became effective in November 2010 and operators were required to implement a programme by 15 November 2011. The regulations apply to all OCS oil & gas and sulphur

Offshore safety

Stop work authority ■■ Ultimate work authority ■■ Employee participation in SEMS programme development and implementation ■■ Reporting of unsafe working conditions ■■ Required use of independent third-party auditors ■■ Additional requirements related to Job Safety Analyses ■■

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BOEM states that they believe “these new requirements will further reduce the likelihood of accidents, injuries, and spills in connection with OCS activities … by requiring OCS operators to specifically address issues associated with human behavior as it applies to their SEMS program.”

operations and the facilities under BSSE jurisdiction, including drilling, production, construction, well workover, well completion, well servicing and DOI pipeline activities. SEMS II Following the implementation of SEMS, US regulators sought to include a number of new proposals that were not covered in the original version. The SEMS rules were released quickly following the Macondo incident and there was no public comment period. However, the next stage, SEMS II, represents regulators’ latest thinking, taking into account stakeholder opinion that was solicited over a period of months. Its formal title is: 30 CFR Part 250. Oil and Gas and Sulphur Operations in the Outer Continental Shelf – Revisions to Safety and Environmental Management Systems. It is often referred to as “SEMS II”. The closing date for comments on SEMS II was 14 November 2011 and SEMS II is expected to come into force in late 2012. Major elements of SEMS II focus on the following new or expanded items:

Learning the ropes Now that SEMS is in place, there are likely to be teething troubles, at least in the short-term, as operators and contractors learn to understand how the BSEE and third-party auditors will construe SEMS requirements. For example, international oil companies have well-developed management systems in place that generally conform to the SEMS requirements in practice, but often have differences in the auditable details. This may create major challenges. The general practice of such companies is to map their existing global management systems to the SEMS requirements and label them as “a SEMS programme.” However, their existing audit programmes must now be supplemented with SEMS audits that meet particular requirements. In contrast, small or new operators

may have relatively nascent management systems that are growing with their operations. When using contractors with mature management systems, they have a choice: they can label their system as their SEMS, or they can review the contractor’s systems for conformance to the new SEMS requirements and adopt them as their own SEMS programme. DNV can assist with bridging documentation and help operators and contractors find practical approaches that are executable and auditable. Another area in which DNV can help is with communication links: key interfaces between operators and contractors. Under SEMS, operators need to ensure adequate processes, documentation and personnel knowledge, even for contractor personnel. In addition, DNV can provide services that supplement existing mechanical integrity documentation to help an operator achieve the desired level of documentation. Conclusion As Stahl concludes. “There is no doubt that SEMS is a significant development for the offshore industry, with the express aim of making it a safer one. The task of companies is to understand what is needed to meet SEMS’ stillevolving requirements for operations in the US OCS. In this respect, DNV is able to provide training on SEMS topics, such as risk assessment, safety culture, human factors, mechanical integrity and environmental risks. This is in addition to our role as a third-party auditor and benchmarking frontrunner.” 

Who are BOEM and BSEE? On 1 October 2011, the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), formerly the Minerals Management Service (MMS), was replaced by the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE) as part of a major reorganisation. BOEM manages the exploration and development of the nation’s offshore resources. It seeks to appropriately balance economic development, energy independence and environmental protection through oil and gas leases, renewable energy development and environmental reviews and studies. BSEE is responsible for the safety and environmental oversight of offshore oil and gas operations, including permits and inspections. Its functions include the development and enforcement of safety and environmental regulations, permitting offshore exploration, development and production, inspections, offshore regulatory programmes, oil spill response and newly formed training and environmental compliance programmes.

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Vattenfall

DNV acquires Vattenfall shares in STRI DNV acquires Vattenfall’s shares in STRI to expand its presence in the power transmission sector.

“The purchase of 12.5% shares in STRI (Swedish Transmission Research Institute) is a natural step in our drive to support both the electrification of the oil and gas industry, as well as the integration of renewable energy and the large investments in the power transmission sector,” says Kjell Eriksson, Director of the Energy Programme in DNV Research and Innovation. “We have known about STRI for many years and started a cooperation agreement in June 2011. Our joint service offering gives us the opportunity to provide integrated solutions to our customers and meet the growing demand in the market place.” According to Mr Eriksson, the electrification of both conventional offshore platforms and subsea oil and gas installations, and the growth in offshore wind energy are the main drivers behind the collaboration with STRI. Both drivers will require new technical and operational solutions to power transmission he says. STRI is a specialist consultancy firm providing advanced studies of high voltage power transmission systems and accredited high voltage testing. “By combining STRI’s knowledge in power systems with DNV’s risk management expertise in offshore installations, we can contribute to setting new, smart demands to what is needed to develop the technology and how to make it robust and reliable enough to transmit large amounts of electricity offshore,” adds Mr Eriksson. “Vattenfall’s use of STRI’s services has declined over the years and we therefore see less of a need to be a partner,” says Karl Bergman, Vice President, Research

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se, dated Press relea 12 March 30, 20

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Kjell Eriksson at DNV and Jörgen Josefsson Senior Advisor at Vattenfall.

and Development at Vattenfall. “The cooperation has been very fruitful, but as our needs have changed, it is now a good time to liquidate our holdings in STRI. We will certainly continue working with STRI but as an ordinary customer.” “Since STRI was founded we have had a very interesting and close collaboration with Vattenfall covering a large number of investigations and R&D projects. It has been a very exciting journey and we are looking forward to keep our good relations and continue our businesses with Vattenfall. With DNV as a shareholder and business partner, the successful development of STRI adds further opportunities for the future. Since our cooperation with DNV

started a year ago, it has become very clear to me that our common resources offer very powerful services to the market,” says Dan Wikström, STRI President, and adds, “DNV is most welcome as a new shareholder in STRI and it will be very exciting to further develop our cooperation.” In December last year, DNV obtained a controlling stake in Netherlands headquartered KEMA, the global energy consulting, testing and certification company as part of a push to expand its presence in the power generation, transmission and distribution sectors. The acquisition of Vattenfall’s shares in STRI will further strengthen DNV’s position in power systems, particularly in the Nordic countries. 

the pOwer tO explOre New FrONtiers

THE POWER TO EXPLORE NEW FRONTIERS tomorrowâ&#x20AC;&#x2122;s oil and gas production will increasingly take place at greater water depths, in harsher environments and remote locations. Only by pushing the technology envelope can we make many of these new fields accessible at acceptable costs and risks. at the same time, future hydrocarbon occurrences will increasingly be located in more fragile environments, necessitating a high degree of reliability and safe operations. we will likely see stricter regulatory frameworks demanding transparent and environmentally sustainable operations.

DNv has built a broad competence base in subsea technology. we provide services ranging from concept evaluation, through product development to manufacturing control and follow-up. we also focus on installation and operational maintenance. when qualifying new technologies, our engineers combine a deep-rooted technology competence with a systematic risk-based approach, so that regulators, operators and industry contractors can proceed with greater confidence in their concept selection, performance and investment.

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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.