Offshore Update 2-2012 by DNV GL (old account)

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Ă&#x2026;lesund offshore cluster

offshore update

News from DNV to the offshore industry

No 02 2012

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Norwegian oil and gas

contents

04 Norwegian oil and gas

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14 24 Ålesund offshore cluster

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offshore update

www.dnv.com Published by DNV Maritime and Oil & Gas, Market Communications Editorial committee: Jan Kvålsvold, Director, Market and Business Development, Division Norway, Finland and Russia Magne A. Røe, Editor Lisbeth Aamodt, Production

Forecasts a long future for Norwegian oil and gas......................................... 4 Island Offshore daring to be different............................................................ 8 In a class of their own..................................................................................... 10 The dynamics of the Ålesund offshore cluster............................................. 14 OSV owners and DNV join forces to reduce fuel consumption................. 20 Energy efﬁciency, an important area for Gulf Offshore.............................. 22 Students develop oil spill contingency concept for the Arctic ................... 24 Do you have access to the best oil spill recovery technology?..................... 29 DNV acquires oil-spill preparedness company NPS..................................... 30 Assisting Statoil – Gullfaks Subsea Compression.......................................... 32 Structural well integrity project gathers pace............................................... 34 Recommended practice for subsea applications.......................................... 38 Veriﬁcation of containment system risers..................................................... 42 Addressing deepwater lifting......................................................................... 44 The next generation safety approach post Macondo.................................. 46 DNV KEMA launches a new certification framework for CO2 storage....... 48 Recommended practices for horizontal directional drilling projects........ 50

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Design and layout: Coor Media 1207-014 Front cover: Sleipner Gas Field, some 250 km west of Stavanger, operated by Statoil. Photo: © Dag Myrestrand/Statoil 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

Long future for Norwegian oil and gas

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

As the global oil and gas industry meets again at Offshore Northern Seas (ONS) in Stavanger, Norway, much has changed since ONS in 2010. More oil has been discovered on the Norwegian continental shelf, not least in the Sverdrup field, which holds resources estimated to be between 1.7 and 3.3 billion barrels of oil equivalents and was the largest offshore oil discovery in 2011. Additionally, the Skrugard discovery in the Barents Sea was the third biggest, and of equal size was the Havis field found in January this year*. This means that we were, and “we” in this respect is the whole oil and gas industry, all wrong and too pessimistic about the future of the Norwegian continental shelf, where production is now expected to increase and peak in 2020. The investments over the next few years will be huge, amounting to hundreds of billions of NOK.

An important agreement between Norway and Russia on the demarcation line between the two countries in the Barents Sea has added some 87,000 square kilometres to the Norwegian shelf and opened up new areas for exploration. All in all, the future is quite positive for Norwegian oil and gas production, and you can read about this in the following interview with Bente Nyland, Director General of the Norwegian Petroleum Directorate (NPD). As we move further north and into Arctic environments, we can see the outline of tomorrow’s oil and gas production, which will increasingly take place in harsher environments, more remote locations and greater water depths. It is only by moving technology limits that we can make many fields accessible at acceptable costs and risks. Managing these business risks is on our agenda

as we stay at the forefront of the development of technology, methodology and practices to avoid any mishaps and the consequences of these. We offer services ranging from concept evaluation, environmental assessment and technology qualification to manufacturing control and follow-up. As the industry moves north, we combine our deep-rooted technology and environmental expertise with our systematic risk-based approach. Also in the global arena, we are active in helping our customers manage risks relating to complex projects and operations. We look forward to continue having an impact in the deep waters offshore Brazil, in the Gulf of Mexico, West Africa, South East Asia, Western Australia and any other area where our expertise can help to reduce the likelihood and consequences of accidents. 

THE POWER TO excel in cold climates

Photo: iStock

* Ola Borten Moe, Minister of Oil and Energy, Norway, speech given at OTC in Houston, 4 June 2012.

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Norwegian oil and gas

Forecasts a long future for Norwegian oil and gas The level of production on the Norwegian continental shelf remains high. In 2010, Norway was the seventh-largest exporter of oil and the second-largest exporter of natural gas in the world. However, the amount of oil produced has decreased since the peak in 2001 and is expected to fall even further. The volume of gas produced is increasing, but the total production on the continental shelf has fallen since 2004. So what will the Norwegian continental shelf’s production level be like in 40 years? Bente Nyland, Director General of the Norwegian Petroleum Directorate (NPD), predicts that oil and gas will continue to be produced in the North Sea, Norwegian Sea and Barents Sea in 2050. Text: Eva Halvorsen, DNV

The Norwegian Petroleum Directorate (NPD) is 40 years old this year. According to its Director General, Bente Nyland, it is a 40-year-old that likes its job and believes its work is important. “Having an independent, professionally strong NPD has been crucial for the first 40 years and will continue to be so for the next 40,” she says. “Oil and gas represent a large part of Norway’s economy and the NPD plays a key role in producing the oil and gas efficiently and on time.” In 1972, there were few who could envisage the Norwegian oil fairy-tale and very few could imagine what the situation would be like today. Even in the NPD, there were many who believed it would be over in the 1990s. “When I took over as Director General five years ago, I sometimes got the feeling that I was the last one. That I would be the person to put the lights out. But the mood has changed following the recent large finds in the North Sea and Barents Sea. We’re now experiencing enormous optimism,” she says. Ms Nyland is a geologist and was previously exploration manager in the management team of her predecessor, Gunnar

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Berge. The NPD is an administrative body under the Norwegian Ministry of Petroleum and Energy and acts as a professional adviser to the ministry. The NPD has just over 200 employees, most of whom are highly qualified professionals. The right thing at the right time Ms Nyland wants the right things to happen at the right time. She has always been interested in increasing the amounts recovered from the Norwegian continental shelf and keeping the production volumes as high as possible. The latest government oil report underlines the industry’s longterm prospects. The main points are clear – there is to be a greater focus on fields in operation, finds must be put into production, there must be more exploration in areas that are already heavily explored and conditions must be made suitable for the opening of new areas. “The volume of oil produced has fallen but we have kept production high for longer than originally planned. The large fields have now been producing for 1.5 times the lifetime they were designed for. That gives us reason to ask whether we are too conservative in our planning,” she says.

Technological developments have made it possible to drill new wells and connect them to main fields and thus increase production. “The companies are making efforts to augment their long-term earnings by increasing their production levels. However, we are not satisfied. Even though the large fields have produced for a long time, they still contain a lot of resources. More than half of the original oil will remain in them when they are closed down – according to current plans. That means it is highly likely that the recovery level can be increased. But that requires the ability and willingness to make the necessary investments. One of our most important tasks is to follow up the industry to help ensure that profitable resources in producing fields are not lost,” says Ms Nyland. She can see that these efforts are worthwhile. Demanding cost level Ms Nyland realises it is difficult to achieve the annual production targets for several of the fields. “Drilling wells is the most important way of maintaining and increasing production, but the companies are drilling fewer wells than planned. The cost level on the

Norwegian oil and gas

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“Drilling wells is the most important way of maintaining and increasing production on the Norwegian continental shelf, but the companies are drilling fewer wells than planned. The cost level on the Norwegian continental shelf is one reason why it is challenging to do this job,” says Bente Nyland, Director General of the Norwegian Petroleum Directorate.

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Norwegian oil and gas

Norwegian continental shelf is one reason why it is challenging to do this job,” she says. Good cost control, new drilling methods and new drilling technology may make it possible to produce more, and Ms Nyland is monitoring developments closely. Costs are also important when new finds are to be developed. Small finds often require access to process and transport facilities in order for the development to be profitable. In mature areas, such finds are usually developed by being connected to independent fields. This also helps extend the lifetime of existing fields. Large finds that are being developed may also depend on spare infrastructure capacity. The coordinated development of several

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finds across exploration licences may reduce the unit costs and make profitable finds even more profitable or lead to the development of finds that, on their own, would have been marginally profitable. “The coordinated development of several finds is not necessarily something the oil companies want, but in connection with new field developments it is our job to look for solutions that may produce coordination gains,” she says. New areas Limiting the fall in production is a political goal requiring efforts to increase production from existing fields, development of discoveries, more exploration in open areas and opening of new areas. According to the NPD, almost

40% of the petroleum produced on the Norwegian continental shelf in 2030 will come from finds that have not yet been made. The number and size of the finds will determine the future production level. Although considerable finds have recently been made in both mature and immature areas, the chances of making a large find are probably greater in some of the unopened areas than in already open areas. As regards Lofoten, she is cautious. “Our job is to state the importance of the resources in a long-term production picture – in a future production profile. The question of drilling in Lofoten is a political issue. Technically, it is manageable.”

Norwegian oil and gas

When the limitation line between Russia and Norway was established in 2011, it became the NPD’s job to map the resources in this area. Bente Nyland is very engaged in the Barents Sea. “For a geologist who has worked on the Barents Sea for a long time, it is good to see the great interest that the latest oil finds have created. This area may play an important role in maintaining production in the long term while also ensuring Norway’s status as a significant and reliable oil and gas exporter,” she says. However, she does not think it is easy to forecast what the production level on the Norwegian continental shelf will be like in 40 years. “There will no doubt

be oil and gas produced in the North Sea, Norwegian Sea and Barents Sea in 2050. Probably also in the new area in the south eastern part of the Barents Sea. We will most likely have started exploration in the Northern part of the Barents Sea too. Maybe there are other forms of oil and gas on the Norwegian continental shelf that proves to be of economic interest, such as gas hydrates and oil shale? I do know one thing, and that is that I will try to ensure that an independent and professionally strong NPD will continue to be important in the future so that our experience and knowledge can be used to recover these oil and gas resources for the benefit of society,” she concludes. 

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Snøhvit LNG Export Terminal, Melkøya Island, Norway.

The Norwegian Petroleum Directorate (NPD) n is a governmental specialist directorate and administrative body n was established in 1972 n reports to the Ministry of Petroleum and Energy (MPE) n is headquartered in Stavanger and has an office in Harstad n has a staff of a little over 200 n The paramount objective of the Norwegian Petroleum Directorate is to contribute to creating the greatest possible values for society from the oil and gas activities by means of prudent resource management based on safety, emergency preparedness and safeguarding of the external environment.

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island offshore

Island Offshore daring to be different Internationally recognised as innovators in the development of specialised vessels and units to serve the offshore industry, Island Offshore continues to push the technology envelope and reap the rewards of being ‘different’.

Operating in a highly risk-sensitive industry that is by its nature sceptical of anything new, Island Offshore has been remarkably successful in introducing innovative concepts, units and vessels. While Håvard Ulstein, Island Offshore’s Managing Director, acknowledges that the company’s initial development costs are high, he argues that there is genuine value in the company’s willingness to challenge technical boundaries. “In the long run, being different makes us more interesting to our partners and, of course, to our clients,” he says. “It pays to be different.” The company currently operates a fleet of 21 vessels (average age: four years) ranging from Platform Supply Vessels to Anchor Handling Vessels, Subsea Construction Vessels and Light Well Intervention Vessels. The company is majority owned by a 50:50 joint venture set up between the US-based Chouest family and the Ulstein family of Norway. Since 2004, Island Offshore (in partnership with FMC and Aker Solutions) has become the world’s leading supplier of Light Well Intervention services. New contracts Recently, Island Offshore announced new contracts for its Well Intervention Vessels (WIVs), the Island Frontier and Island Wellserver. These state-of-the-art vessels have been awarded a five-year (plus options for a second five years) contract by Norwegian oil company Statoil, beginning in April 2015. “So far, we have carried out more than 250 well interventions, averaging around 50 interventions per year,” says Ulstein.

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Text: Damien Devlin and Robert Ward

“In the long run, being different makes Island Offshore more interesting to our partners and, of course, to our clients.” Håvard Ulstein, Managing Director, Island Offshore

Ulstein explains that the well-intervention business is very complex, but that the company has demonstrated its ability to be a major force in this sector. “As offshore (E&P) and production expands around the world, there will be many more subsea vessels built in the near future,” he says.

“But it is not only intervention technologies that need to be considered, you must be able to provide associated services, such as being able to handle ROVs. For this reason, it is critical that we have close relationships with our customers to make sure we are delivering to their requirements.” At present, the company is in the middle of a five-vessel newbuilding programme, and all the ships are to be built by the STX OSV Brevik yard. The first platform supply vessel (PSV) was delivered in July, with another delivery expected in September. The subsea construction vessels will be delivered in 2014. The entire Island Offshore fleet is and will be classed by DNV. Long-term perspective Island Offshore’s executives have consistently stated that offering dedicated services for the offshore industry is not a sector that sees short-term returns due to the needs of a specialised fleet. Tommy Walaunet, the company’s Deputy Managing Director, explains: “What profit we make we spend on building new vessels. But our shareholders know we are playing the long-term game.” This dedication to building a credible long-term business is what will bring ultimate financial success. Ulstein adds that, because Island Offshore is a relatively young company (established in 2004), it will be important to expand the fleet and area of operations. “Unlike many companies, we will expand by buying new vessels,” he says. “Buying second-hand ships is not part of

island offshore

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Island Chieftain multi purpose offshore vessel.

our strategy. By building bespoke vessels, we are ensuring we have what the industry demands.” Bright future Looking ahead, Ulstein is confident about the company’s future. “Our expansion comes at a time when we are seeing increased investment by energy majors. Indeed, capex spending is expected to double in some key regions, such as West Africa and Brazil,” he says. “We also anticipate increased demand for more fixed, floating units and increasing pipelaying activity up to 2015 and beyond.” This global growth is helping to keep vessel rates high. Ulstein acknowledges that day rates for well intervention work have been good. “A number of new contracts have been signed recently at rates of around USD 1.5-2 million per day, all inclusive. ” While all the vessels in Island Offshore’s newbuilding programme are unique, one newbuilding confirms Island Offshore’s

“we like-to-be-different” tag. The Island Crusader PSV is the first UT776 CDG (the G stands for gas operation) to be built in Norway. At the same time, two PSVs – the UT 776 pair of Island Centurion and Island Captain – will soon be converted into well stimulation vessels. Their sister ship, the Island Commander, is already working as a well stimulation ship. Leaders in well stimulation Supplying well stimulation vessels is where Island Offshore has really made its mark. Along with its US partner Edison Chouest, Island Offshore currently operates 12 of these very specialist vessels, accounting for almost 50 per cent of the total of 25 such vessels operating worldwide. Frode Holm, DNV’s Station Manager at Ulsteinvik, has seen first-hand the speed at which Island Offshore is growing, and is working to ensure that DNV can contribute to this success. “In just a few short years, Island Offshore has become a major

force in the specialised offshore services sector,” he says. “We have supported them by being involved in the design of their vessels at an early stage, solving design problems before an issue becomes too costly to fix.” He adds: “Having an office in Ulsteinvik has helped cut response times and improved communication with Island Offshore through enabling closer contact with them. Having a single point of initial contact also helps this process.” Looking ahead With a clear strategy of focusing on highly specialised services using dedicated vessels, Island Offshore’s future looks bright. “We already have an excellent fleet that will be augmented by a number of additions in the next couple of years. Add to this the fact that the E&P market is looking strong and that we have excellent relationships with our customers, and we are confident that our business will go from strength to strength.” 

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DNV Ålesund

In a class of their own Since opening for business in Ålesund in 1918, DNV has become an integral part of the Møre shipping cluster on Norway’s west coast. Today, DNV has almost a 100 per cent share of the newbuilding market, which is testament to the fact that it continues to provide value to the region’s many designers, yards, owners and equipment manufacturers.

“In the yards in Møre, people don’t walk, they run,” quips Fredrik Hessen, DNV’s District Manager, describing DNV’s approach to service in the region. Over nearly a century, DNV’s working practices – 24-hour availability and rapid response time – have become aligned with the local culture. “This has been the key to our success, and is the result of nearly a century of experience in the region.” In that time, DNV has been more than just a classification society. In 1955, Alf Tveten brought his knowledge of welding from Oslo to Møre as the new DNV station manager in Ålesund. His influence in aiding the conversion to steel ships was a pivotal moment in the region’s shipbuilding his-

Photo: DNV

Text: Damien Devlin

construction vessels and well intervention ships – one of which may well be “Ship of the Year” in 2012. Together, the shipowners in the Møre cluster operate 230 vessels, made up of fishing vessels, OSVs (offshore support vessels), cargo vessels and seismic vessels. In addition, DNV certifies quality systems at shipping companies and ships in the region according to ISM, ISPS, ISO 9000 and ISO 14000. DNV also certifies the materials and components that go on board the ships. Several of the cluster’s members design and manufacture equipment, and electronics is a new area in which the cluster is becoming stronger. Now, at least 11

“Møre is an exciting area to work in. It’s a real innovation hub.” Fredrik Hessen, District Manager tory and a reason why one of Møre’s most respected voices, Sigbjørn Akselvoll, former Yard Director at STX OSV, proclaimed, “DNV has contributed strongly to the development of the shipyards in this region.” Today, the cluster comprises globally recognised shipping companies that sprung up from an area with a population of just 130,000. The success enjoyed by this

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region is demonstrated through their domination of the Norwegian “Ship of the Year” award, which was presented nine times between 2000 and 2010 to ships designed and built by cluster members. All of these vessels were classified by DNV, as were over 300 other ships in Møre during that period. Recently, DNV has overseen the newbuilding of hi-tech offshore

companies design, develop and build integrated electronic systems, such as alarm, remote control and advanced automation systems. Boom time While orders in other shipbuilding regions in the world are waning, the yards in Møre are operating at full capacity. In 2003 and early 2004, there

DNV Ålesund

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City of Ålesund.

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DNV Ålesund

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City of Ålesund.

was a lack of contracts. However, in late 2004, things picked up rapidly and soon the yards experienced a boom unlike any other before. Since then, they have had long order books and a temporary slowdown in 2009 had little to no effect. So far this year, Norway has won 60 newbuilding contracts (over half of which have gone to yards in Møre), the same as it managed during the whole of 2011, which was considered a bumper year. DNV opened an approval support office in Ålesund in 2007 to provide the quick service its customers require. Hessen explains that a short response time is important. “The yards in this area know

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the cost of delays and so really appreciate quick service,” he says. Since opening the new approval support office, DNV has cut response times and improved communication with its customers through closer contact. Personnel are involved early in the design phase so that issues can be solved before they become serious. “Our customers have given us excellent feedback on speed, service and availability. We can now give them support where and when they need it,” says Hessen. DNV supports the designers, yards, owners and suppliers with consulting services in specialised disciplines such as noise and vibration, rotating machinery,

hydrodynamics and the qualification of new technology from its main office at Høvik. These services have seen an increase in demand, as has management consulting with regard to internationalisation and strategy, risk analysis, energy efficiency and operational improvement. DNV has now established an advisory unit in Ålesund with a focus on technical consulting services, management consulting, innovation and international cooperation. To keep up with the demand for all of its services in the region, DNV has increased its staff in Møre from 29 in 2003 to around 60 today. That additional capacity required extra office space in Ulsteinvik

DNV Ålesund

and Kristiansund and DNV Ålesund relocated to new premises last year. Driving innovation While Hessen acknowledges that keeping up with the rapid pace of innovation in the region has been a challenge for DNV, he notes that the organisation’s work in classifying new technologies has helped strengthen the technical expertise of DNV personnel. “The rules will always lag behind the technology, and the technology has moved fast,” he says. “In order to keep up with the development of new technology, we have had to develop new rules and class notations to suit the market needs.”

Crew feedback In Norway, flat organisational structures are the norm. The lack of hierarchy is especially noticeable in the Møre region, where you often see shipowners in boiler suits rather than business suits chatting with workers on the deck. As a result, designers, yards and equipment makers actively seek the feedback of the crews and Hessen believes that this is one of the reasons for the cluster’s success. “You cannot overstate the role the crews have played in the companies’ success in Møre,” he claims. “The people operating the ships and equipment have a better understanding of how they are used than anyone. Farstad, for example, bring their

chief engineers, captains and other crew to meet designers, yards and manufacturers when they are planning new vessels.” This encourages a collaborative environment where the best idea wins, and DNV has also benefited from this approach. Some of its class notations, for example, have been proposed by shipowners, including FiFi, the firefighting notation. “It’s an exciting area to work in,” Hessen says of Møre, “It’s a real innovation hub. We just hope to aid them on their way by providing the service they expect, when and where they need it.” 

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Ålesund offshore cluster

Compete, cooperate and innovate:

The dynamics of the Ålesund offshore cluster Located on the west coast of Norway, the Møre and Romsdal region is characterised by a jumble of scenic islands and snow-capped mountains divided by steep-sided fjords. Yet for all its natural beauty, the region is also home to one of the most complete offshore and shipping clusters in the world. Text: Alexander Wardwell

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Ålesund offshore cluster

From shipowners to shipyards, marine services to equipment manufacturers and a deep pool of highly skilled local seafarers, the Møre and Romsdal region produces the industry’s most advanced, sophisticated and innovative OSVs that continually push the boundaries of technology and design. Indeed, many groundbreaking advances in fuel-efficient propulsion, hydrodynamic hull forms and new vessel types have their origins in the region, where innovation is driven as much by cooperation as by competition. Ålesund is built on herring The origins of the cluster can be traced back centuries, when the local population supplemented their income from farming by fishing – mostly herring and cod that spawned in the rich marine ecosystem off the coast. When the fish disappeared from the calm waters of the fjords, local entrepreneurs built more seaworthy steel-hulled ships that could navigate the rougher waters of the North Sea. In time, fishermen invested in new, larger vessels, leading to the construction of more shipyards and small factories producing specialised equipment. By the 19th century, Ålesund – one of the larger coastal towns in the region – was known as “The Town Built by Herring – the Silver of the Seas”. With the introduction of the internal combustion engine, vessels soon grew larger and were equipped with increasingly sophisticated equipment, such as motorised winches and deck cranes to haul in fishing nets. Fishermen and equipment suppliers worked closely together to develop new, more efficient vessel types and engines, forming an integrated business culture characterised by competition, cooperation and technical innovation. Indeed, the region continues to produce next-generation fishing vessels and is a pioneer in LNG-powered coastal ferries. Everything began to change in the 1970s, when Norway struck oil and its burgeoning offshore industry required support vessels. Fredrik Hessen, DNV’s District Manager, explains that the vessels brought in from the Gulf of Mexico were not suited

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Ålesund offshore cluster

trade secrets with competitors, but we all recognise the benefits of sharing knowledge – an approach that benefits everyone.”

“We cooperate when we can and compete when we have to. Competition drives different players to outdo one another, while cooperation helps strengthen the overall cluster.” Børge Nakken, Vice President, Technology and Development, Farstad Shipping

to the harsh conditions on the Norwegian Continental Shelf. The shipping industry in Møre soon realised that the OSVs used in other parts of the world were not suitable for the local environment. In time, many fishing vessels were converted into OSVs and simply adjusted to the requirements of the offshore industry. Local expertise, global reach Today, the region is internationally recognised for building high quality OSVs that are active not only in the North Sea, but also off the West Coast of Africa, Australia, Brazil and India, in the Gulf of Mexico and in a number of offshore fields throughout Asia. The region is dotted with specialised shipyards, including Kleven, Ulstein and four owned by STX OSV (Langsten, Brattvaag, Søviknes and Aukra), serving global shipping companies

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like Farstad, Island Offshore, Havila, Olympic Shipping and others. These companies are served by a network of suppliers like Rolls-Royce, Kongsberg Maritime, Brunvoll (thrusters), MaK (propulsion), IP Huse (winches and cranes) and DNV, all working together to push technical boundaries. But how do all these different stakeholders, which often compete for the same contracts, work together to create such a strong, integrated cluster? Børge Nakken, Vice President, Technology and Development at Farstad Shipping, says that what makes the cluster unique is grounded in history, a sense of local pride and a willingness to work together. “We cooperate when we can and compete when we have to,” he says. “Competition drives different players to outdo one another, while cooperation helps strengthen the overall cluster. Of course, no one shares

A fully integrated cluster Nakken notes that the shipowner remains the engine of the cluster, which also involves shipyards, equipment manufacturers, marine services suppliers and seafarers. These stakeholders are further linked by a network of technical schools, universities, training centres and related specialised organisations, like the Norwegian Centre of Expertise (NCE-Maritime) in Ålesund. In addition, many stakeholders participate in Joint Industry Projects focused on developing innovative solutions to manage specific challenges which are unique to the industry. For Farstad, the innovation process is driven by three elements: customer requirements, safety and environmental performance. “A big part of what we do is to listen to our customers carefully to understand the specific challenges they face, and develop the solutions, together with our suppliers, to meet those challenges,” says Nakken. “At the same time, we are always pushing to develop new solutions that we are confident will be attractive to the market in the future.” A standardised approach Nakken adds that because the company seeks a standardised approach to equipment and systems on all its vessels, it tends to work with the same suppliers over time. “We also benefit from the quality and experience of our seafarers, who we encourage to participate in the innovation process,” he says. “A lot of changes we make on board are inspired by the people who live and work at sea.” The company’s ambitious newbuilding programme (which saw its first delivery earlier this year) is a good example of how this process works – and how the cluster works together – to get the job done. Two of the more recent additions to Farstad’s fleet, which will have increased by 12 vessels (a mix of PSVs and AHTSs) by the end

Ålesund offshore cluster

“The strength of the cluster is not confined to the achievements of individual companies, but is also in the way that each organisation shares knowledge to build our collective expertise. In addition to producing truly innovative vessels, this approach helps retain a high level of competence and expertise that you can’t find anywhere else in the world.” Svein Kleven, Senior Vice President, Innovation & Technology (Offshore) Rolls-Royce

of 2016, are the Far Scotsman (delivered in July) and the Far Solitaire, on schedule to be delivered in October. Both were constructed by STX OSV and outfitted at STX OSV’s yard in Langsten. Optimised for fuel efficiency The Far Scotsman is a 3,000 gt PSV, designed by STX OSV, with Rolls-Royce propulsion and DP systems and classed by DNV (1A1, DYNPOS AUT, DNV Comfort, Clean Design among others). According to Steinar Nerbøvik, Senior Vice President and Yard Director for STX OSV Langsten, the vessel features Rolls-Royce azipull propeller systems, a hull form optimised for stability in rough seas and a triple engine configuration that helps reduce fuel usage significantly.

“We worked closely with Farstad and Rolls-Royce to develop a flexible diesel electric propulsion system that would both exceed compliance rules on safety and the environment and help lower fuel consumption and corresponding emissions,” he says. “The result allows the master to use one engine for steaming, two when approaching the rig, and three in heavy seas when necessary. It is flexible, but provides the redundancy required when operating close to offshore installations or in challenging sea conditions.” A history of excellence Nerbøvik says that STX OSV Langsten has produced a number of groundbreaking vessels, including five that have been awarded “Ship of the Year” honours by Skipsrevyen,

a leading maritime journal. In the yard’s 70-year history, STX OSV has built about 25 vessels for Farstad, including 10 at the Langsten yard alone. Its module approach to shipbuilding and ability to build and outfit vessels in different yards has helped the company manage cyclical changes in market demand more effectively. “By being part of the cluster, we not only have the opportunity to build longterm relationships with shipowners, but also have access to a very strong local talent pool of engineers, designers and skilled yard workers that has helped us maintain our competitive edge and share competencies with other STX OSV yards in our global network,” he says. “At the same time, our close cooperation with suppliers allows a more efficient build process – we all know each other and understand our different roles and responsibilities.” Groundbreaking design At present, STX OSV Langsten is outfitting a second vessel for Farstad, the Rolls-Royce UT 754 WP PSV Far Solitaire. Nakken explains that, in response to demand from energy companies, the company sought to produce an IBC Chapter 2 compliant PSV for the safe transportation and handling of noxious liquids above the limit of 800 cubic metres, as defined by existing IMO rules. “PSVs are classed as cargo vessels, which limits the amount of noxious liquids allowed on board,” he explains. “When launched in October this year, the Far Solitaire will be the first PSV that is compliant with rules usually applied to chemical tankers, so that we can safely transport larger amounts of toxic liquids.” STX OSV won the contract to build the Far Solitaire, but the design of this unique vessel was awarded to Rolls-Royce Marine Ship Technology (Offshore). While Nerbøvik notes that the two companies sometimes compete to win design contracts, he insists that STX OSV’s relationship with Rolls-Royce remains strong. “Sometimes we compete, but we also value our cooperation with Rolls-Royce and work to strengthen the relationship in order to deliver quality tonnage to our customers,”

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Ålesund offshore cluster

“By being part of the cluster, we not only have the opportunity to build long-term relationships with shipowners, but also have access to a very strong local talent pool of engineers, designers and skilled yard workers that has helped us maintain our competitive advantage.”

Steinar Nerbøvik, Senior Vice President and Yard Director for STX OSV Langsten

he says. “In my view, it is this ‘compete cooperate’ dynamic that makes the cluster so strong.” Shared objectives Svein Kleven, Senior Vice President Innovation & Technology (Offshore) at Rolls-Royce, agrees. “We may compete with STX OSV from time to time – in particular within the ship design market, but we have worked closely with them for decades and view our relationship with STX OSV as strong. STX OSV remains a major customer for Rolls-Royce equipment and system solutions,” he says. “After all, we share the same goal – to deliver or exceed customer expectations.” In addition to a higher noxious liquid capacity, the Far Solitaire has a number of other innovative design features. The vessel features a Rolls-Royce propulsion and DP system and design-protected ‘Wave Piercing’ hull form, which eliminates slamming and allows a smooth ride even in rough weather conditions, reducing fuel consumption and improving crew comfort. The vessel is also the first PSV with a dual draglink crane (manufactured by

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Rolls-Royce Deck Machinery and IP Huse) on the starboard side cargo rail, covering the full length of the cargo deck, which increases the work area and ensures a stable horizontal movement. Holistic approach to innovation Kleven says that what makes Rolls-Royce unique is the way in which the company approaches innovation. “High quality equipment and system engineering remain critical components of the process, but we also take into account supply chain logistics, maintenance, quality assurance and after-sale services that cover the life cycle of whatever product we offer,” he says. “This holistic view provides better service to our customers and strengthens our long-term relationships with owners, shipyards and our own suppliers.” As a leading player in the cluster, RollsRoyce is active in a number of JIPs and research and development programmes, working in cooperation with local and international organisations and universities. “The strength of the cluster is not confined to the achievements of individual

companies, but is also in the way that each organisation shares knowledge to build our collective expertise,” he says. “In addition to producing truly innovative vessels, this approach helps retain a high level of competence and expertise in the region that you can’t find anywhere else in the world.” A class apart As the regional market leader in classification and related services, DNV plays an active role in the cluster. According to Hessen, the organisation works closely with owners, yards and suppliers on a broad range of projects. “While the core of our activities is the classification of newbuildings and ships in operation, we are actively involved in technical support and the verification of new vessel concepts,” he says. “Our primary role in the cluster is to support innovation by helping stakeholders manage risks related to safety and environmental performance.” In addition to technical support, DNV is also in a strong position to work with regulators and flag states to approve new

systems or types of vessels. For example, DNV worked closely with Farstad, RollsRoyce and the NMA (Norwegian Maritime Authority) to win approval to increase the capacity of the Far Solitaire so that it could carry 1200cm of noxious liquids. “We supported Farstad in their efforts to ensure the vessel was compliant with the IMO’s IBC Code, which applies to ships that carry dangerous chemicals in bulk,” says Hessen. “Our challenge was to help manage potential risks associated with stability, layout, tank structure and configuration to allow increased capacity for dangerous chemicals.” Hessen says that the result is a PSV that includes design features not usually found on PSVs, such as gas detection equipment and segregated cargo pumps and piping systems to avoid risks related to mixing different hazardous chemicals. In addition to providing valuable technical support from its headquarters outside Oslo, DNV also opened an Approval Centre in Ålesund in 2007. “This allows us to respond more quickly to local requests, such as for refits and upgrade projects,” says Hessen. “And since many of our customers operate around the world, they have local access to DNV’s expertise through our global network.” Regional pride Scheduled for delivery in October, the Far Solitaire and Far Scotsman are two examples of how the Ålesund cluster works to produce cuttingedge PSVs. And while both vessels are owned and operated by Farstad, there are many individuals in the region who feel a sense of ownership in these groundbreaking vessels. “We may all work for different companies and organisations, but everyone shares a sense of collective pride in the work we do,” says Hessen. “The cluster may be driven by healthy competition between owners and suppliers, but what makes it special is how everyone works together.” 

Ålesund offshore cluster

“Our primary role in the cluster is to support innovation by helping stakeholders manage risks related to safety and environmental performance.” Fredrik Hessen, District Manager, DNV

DNV’s CLEAN DESIGN The CLEAN DESIGN notation requirements are intended to reduce and limit the ship’s air emissions and sea pollution. In addition, DNV’s CLEAN DESIGN notation stipulates defensive design, accident prevention and consequence limitation requirements, thus providing additional environmental protection. For owners interested in promoting an environmental profile, the notation confirms a higher environmental standard. Features of the notation include the protection of fuel tanks from grounding damage, proper handling of sewage, waste, ballast water and fuel oil, proper use of refrigerants, and control and limitation of operational emissions and discharges, among others.

Building the fleet In addition to the Far Scotsman and Far Solitaire, Farstad has awarded STX OSV a contract for the construction of two Multifunctional Deepwater Anchor Handling/Offshore Service vessels. The vessels will be of Rolls-Royce’s UT 731 CD design. Deliveries are scheduled from STX OSV’s Langsten yard in the first quarter of 2014. More recently, Farstad announced another contract with STX OSV to build two additional platform supply vessels. The steel hull of one of the vessels will be built in Romania and the outfitting yard will be STX OSV Langsten. The other vessel will be built at the STX OSV yard in Vung Tau, Vietnam. Delivery of the vessels will take place during the second and third quarters of 2014 respectively. The PSV newbuildings will service the six-year charter contracts recently awarded by Statoil. The vessels will be built according to DNV’s strictest environmental class – “CLEAN DESIGN.”

offshore UPDATE NO. 2 2012 |

Reduce fuel consumption

OSV owners and DNV join forces to reduce fuel consumption Seven Norwegian owners of offshore support vessels (OSVs) and DNV have joined forces in an initiative to reduce fuel consumption. The second phase of the initiative is now starting, and oil majors will join the group. Text: Sverre Alvik, DNV

Seven shipping companies – BOA Offshore, Eidesvik Offshore, Farstad Shipping, Gulf Offshore Norge, Havila Shipping, Siem Offshore and Solstad Offshore – together own and operate 170 vessels. For the past eight months, these companies have been working together with DNV in a Joint Industry Project focusing on how to operate their vessels with reduced fuel consumption. Research and practice have shown that, in shipping, there are many ‘low-hanging fruits’ that can reduce fuel consumption and costs. In the offshore industry, however, contractual barriers and the lack of economic incentives often prevent many good solutions from being implemented. IMO has also seen the potential here, and new requirements for all ships to prepare and implement a Ship Energy Efficiency Management Plan (SEEMP) will become mandatory in January next year. In the group’s first project, an improvement potential of a 16% reduction was identified. With the shipping companies’ 170 vessels emitting around 1.7Mt of CO2 every year, the initiative will have a considerable positive impact on the environment.

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Getting the charterers involved will ensure these savings, cut the charterers’ fuel costs and make sure the initiatives spread to other vessels too. With high fuel prices and an increased stakeholder focus, energy efficiency is making its way up the offshore industry’s agenda. New high-tech ships being built have hulls and engines designed to consume less fuel and, for vessels on charter, both operator and charterer have initiatives to reduce consumption. In many areas – particularly related to new technology – successful results have been achieved. On the other hand many – often operational – initiatives are never implemented due to different views and priorities in the industry and the lack of incentives to ensure successful results. By joining forces, the companies can achieve even more. The seven owners and DNV have established a group called Energy Efficient Offshore Partners (EEOP). The group’s first project was to establish a common platform of current practices and improvement opportunities and, based on this, create a document containing industry best practices. Examples of key focus

areas are DP operation, propeller polishing and communication with the charterer. A common platform with agreed initiatives will be much easier to communicate and implement in the industry. To ensure the successful implementation of the initiatives, the group should include charterers. Invitations to join the EEOP were therefore sent to charterers operating in Norwegian waters before the summer, and several of them, including oil majors Statoil and ConocoPhillips, have accepted. They see that the initiative fits in well with their own ambition to save costs and reduce their environmental footprint. The next project will start in August and have three key focus areas: ■■ Procedures and guidelines ■■ Communication framework ■■ Incentive schemes The shipowners and charterers will then look into these and other areas with the aim of finding common solutions that benefit all parties. This will be achieved through the following project steps: solution development, pilot testing and implementation. 

Reduce fuel consumption

THE POWER OF being Fuel EFFICIENt

ÂŠ Getty Images

Fuel is a major cost item today and DNV can assist with all aspects of reducing fuel consumption. Our experts have experience ranging from the implementation of operational energy management services to technical solutions, such as hull optimisation for newbuildings and retrofitting of fuel saving devices on existing ships.

offshore UPDATE NO. 2 2012 |

Gulf offshore

Energy efﬁciency, an important area for Gulf Offshore Interview with Erik Utne Eikehaugen, Operations Manager at Gulf Offshore Norge

There are three main reasons explaining why energy efficiency is important for Gulf: firstly the environmental side, it is important to reduce emissions. Secondly, fossil fuel is a limited resource that it is important to exploit in the best possible way. And thirdly, reduced consumption is a saving for our customers, reducing their costs. For these reasons, there will be an increased focus on reducing fuel consumption, and it is important to look at ways to do this. Text: Sverre Alvik, DNV

Why did Gulf Offshore decide to join the group of seven OSV owners? “We look upon DNV as a quality vendor of services, both class and projects, and are therefore interested when you take the initiative regarding this type of activities. We see synergies from working with other companies in the same segment, learning from each other and exchanging experiences and best practices, ensuring improved results. The other companies participating are companies we would like to work together with in the effort to form common guidelines for better energy efficiency and we therefore decided to join.” What is it like to cooperate with companies you could compete with on a contract tomorrow? “We have no problems at all doing this. We have the same environmental goals and

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all of us want to use the resources in the best possible way. For the industry, it is a strength that we can work together and learn from each other.” Which areas would you highlight as having large potential for the industry to improve? “I think cooperation between us as owners and our customers as operators has the highest potential. Improved logistics, both planning and execution, including areas such as improved utilisation and right speed, is important. As a group we should be able to achieve much more than if we worked individually with the charterers on this. For Gulf as an individual company, I think working on culture and attitude and thus increasing the crew’s awareness of energy efficient operations is the most

important issue. Creating an attitude within the onshore and offshore organisation has higher potential in the long run than only focusing on specific technical means. Improved cooperation and culture are not low-hanging fruits. It takes time to change attitude and behaviour. But, over time, our efforts will make things happen and be efficient for the environment, resource allocation and the overall economy.” Charterers and oil majors will join the next phase of the initiative, what are your expectations of them? “I expect the oil majors to work with the group and actively look to identify and implement measures to improve energy efficiency. I don’t think we will see a lot of changes over night, but over time attitudes

Gulf offshore

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Erik Utne Eikehaugen, Operations Manager at Gulf Offshore Norge.

will change in all of the industry, including in the charterers’ organisation, ensuring improved results. When they see that the industry has an ambition, they will follow up. One main challenge the project will face is to get the cooperation between the shipowners, the charterers’ logistics centres and the charterers’ offshore organisations to work well. We have to avoid good intentions being blocked by individual ideas and causes.”

will work on issues such as hull cleaning, propeller polishing, installing econometers on board and establishing a baseline for consumption.” Based on what you have seen so far, are you confident that this will be a successful initiative? “If this group doesn’t succeed, who can? The project has already been a success; we are a considerable group that has already identified and started to implement effective measures.

In closing, I would like to say that we in Gulf find it motivating to join a group with the potential to inspire and change the entire industry. We hope the guidelines and practices over time can be applicable to all players, in Norway and globally, thus improving the energy efficiency of the offshore industry.” 

You as owners also have a responsibility, can you give some examples of actions you would like to carry out? “On the newbuilding side, we already focus on energy efficiency design and installing equipment that promotes efficient operations. On the operational side, we

offshore UPDATE NO. 2 2012 |

Student project

Students develop oil spill contingency concept for the Arctic DNV’s summer students have presented the results of seven weeks of intense and targeted work to develop a realistic and suitable concept for a year-round Arctic oil spill response system, including requirements for people, vessels and equipment. Text: Eva Halvorsen, DNV

importance. These are complex issues that the world’s leading scientists, researchers and engineers spend considerable time and resources on. So I am impressed by what these ten students have been able to process and produce during seven short summer weeks,” said DNV’s CEO Henrik O. Madsen.

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The cornerstone of the concept is a multifunctional concept vessel – the Boreast – capable of performing oil spill response tasks in the Arctic. Illustration: © DNV

DNV’s summer project is an annual programme organised during the summer months for students in their final year of a master’s degree programme. This year, ten students with varied cultural and academic backgrounds worked intensely on their project for seven weeks. The focus was

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on developing an Arctic oil spill response system. “We know that the world needs more energy. And we know that much of this energy is located in unfriendly and vulnerable areas of the world. Adequate oil spill response systems are therefore of vital

Realistic and innovative Research shows that about 22–25% of the world’s undiscovered petroleum resources are located in the Arctic. However, there are many complex challenges related to drilling in this region. One of these is to have a system in place should an accident occur. “We presented a realistic, innovative Arctic oil spill response system we have called the AURORA – Arctic United Response Operation and Recovery Agreement – combining new ideas and fresh insight,” explained project manager Martin Andestad. The main purpose of an oil spill response system is to limit the consequences of an oil spill, and the methods are divided into three categories; mechanical recovery, non-mechanical recovery and manual recovery.

©DNV/Damir Cvetojevic

Student project

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Ten students with varied cultural and academic backgrounds worked intensely for seven weeks this summer: The men, from left: Preben Østevold, Tero Tervahartiala, Sondre Henningsgård, Peter Lindersen, Viktor Ogeman, Martin Andestad, Andreas Størdal. The women, from left: Tina Sætrum, Josefin Svensson, Melissa Denbaum.

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“Adequate oil spill response systems are of vital importance, and these are complex issues that the world’s leading scientists, researchers and engineers spend considerable time and resources on. I am impressed by what these ten students have been able to process and produce during seven short summer weeks,” said DNV’s CEO Henrik O. Madsen.

Three oil spill response levels The AURORA is divided into three oil spill response levels. The first response is conducted by on-site vessels. The second is conducted by vessels arriving from the closest cold or warm hub. The third, which includes beach clean-up, is a large mobilisation by all hubs. The hub locations are chosen based on the existing infrastructure along the Northern Sea Route. Warm hubs contain all the equipment included in the AURORA, while cold hubs function as extensions of the warm hubs. Multifunctional concept vessel The AURORA’s cornerstone is a multifunctional concept vessel – the Boreast – capable of performing oil spill response tasks in the Arctic. This vessel has a

number of innovative solutions on board; an unmanned aerial vehicle, remote insitu burning, an autonomous underwater vehicle, towable storage bladders and an ice cleaning conveyor belt to mention a few. The AURORA further combines efficient logistics, appropriate vessels, a wide range of equipment and human expertise to create an oil spill response system with high performance and low cost. The students presented the concept in two scenarios; a drilling rig blow-out and a cargo ship grounding. But as they said: “The AURORA states a high level of preparation, but this might not be enough to ensure safe operations in the future. In the Arctic, there is no room for a weak link.” 

offshore UPDATE NO. 2 2012 |

Future challenges

Future Challenges The Arctic is opening and activity is increasing. Even with the most well-thought-out oil spill response systems there is still lack of hands-on experience regarding large scale operations in the area. To predict the unpredictable is impossible and therefore preparation is everything â&#x20AC;&#x201C; one cannot be too prepared. The Arctic has to be treated with respect. To bring training and equipment to an acceptable level requires funding and understanding. Since the Arctic conditions differ significantly from most other regions there will be need for regular training and testing of equipment and personnel. Finally, cooperation between stakeholders is a key to success. The AURORA states a high level of preparation. However, it might not be enough to ensure safe operations in the future. In the Arctic, there is no room for the weakest link.

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ÂŠ Getty Images

Future challenges

offshore UPDATE NO. 2 2012 |

oil spill recovery

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oil spill recovery

If an oil spill happens – do you have access to the best oil spill recovery technology? Although they are unlikely, accidents such as Macondo in the Gulf of Mexico and Montara in the Timor Sea do occur. Common to such events is that they can have major consequences for both the environment and the responsible oil company. Local communities, such as the fisheries and tourist industries, are often heavily affected. Text: TOR JENSEN, DNV

All oil and gas operators on the Norwegian continental shelf have the requirement of having a field-specific oil spill preparedness analysis and plan in place embedded in their operating permits. However, their actual preparedness for and ability to operate effectively during an incident are increasingly being questioned. With just fractions of the oil released in a spill documented as being recovered, oil spill response operations have been criticised as inefficient and insufficient. The evaluation of oil recovery operations shows that several factors are important for the efficiency of the operation. In general, the weather conditions are of huge importance and oil recovery equipment has shown little effect in rough seas. Further, it is crucial to track where the oil is and where it is drifting. The equipment must be tailored to the type of oil and to the operating conditions. Last but not least, the skills of the crew operating the oil spill equipment are very important. There is growing concern that significant parts of the mechanical equipment used and methods applied during an oil spill recovery operation do not actually perform as expected. Moreover, there is a lack of functional requirements

for and documentation of the efficiency of the equipment being used today. Hence, we do not actually know exactly what to expect from any tool or equipment used. This is now a matter of concern to the oil companies as well as governments. Secondly, there is growing consensus among the players in the oil and gas industry that the level of innovation and technology development of oil spill recovery methods and equipment needs to increase, and that “next-generation” solutions need to be used. This will be of particular importance in harsher and more environmentally sensitive areas. Thirdly, the industry does not currently take a systematic approach to ensure that the equipment and technologies available (and under development) have the proper functionality and efficiency under various conditions and in a life-cycle perspective. Hence, the oil companies find it difficult to document the actual efficiency of their planned oil spill preparedness. It would benefit the industry if national test facilities and a test regime were put in place so that the different manufacturers could test different solutions according to a set of functional requirements. This

would increase the confidence in the equipment, as critical components would be tested at certain intervals and against a common standard. DNV, SINTEF and the newly DNVacquired company NPS have therefore taken the initiative to launch a joint industry project (JIP) on Oil Recovery Technology (ORTech), with the main objective of developing a common industry framework that will describe the functional requirements of typical oil spill recovery equipment. A guideline will be written based on consensus in the partnership and with other key stakeholders. The guideline will describe a test regime for critical components and point out the need to apply such a regime in order to increase the overall confidence in and efficiency of the oil spill prevention and recovery approach on the Norwegian continental shelf and elsewhere. The ORTech JIP has been presented to some of the most relevant oil companies operating on the Norwegian continental shelf and to the Norwegian Coastal Administration. The feedback has so far been positive and the project group aims for a JIP start-up during the autumn of 2012 or in early 2013. 

offshore UPDATE NO. 2 2012 |

NPS

DNV increases its Arctic focus and acquires oil-spill preparedness company NPS The Arctic has large oil and gas resources, and operations in this sensitive and harsh area will require efficient oil-spill preparedness solutions. “The acquisition of Norwegian Petro Services (NPS) in Norway and its recognised expertise will play an important role in our activities in this field,” says Knut Ørbeck-Nilssen, the COO of DNV’s Division Norway, Russia and Finland. Text: Linn Marie Pickard

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NPS

contribute to this, and the acquisition of NPS is an important strategic move in that sense. We are now combining DNV’s environmental risk and oil spill preparedness analyses with NPS’s specialist expertise in planning and organising oil-spill preparedness. This provides a complete service portfolio for our customers,” says Ørbeck-Nilssen. NPS – a DNV company “NPS, which consists of five professionals, will give us operational expertise that is important to the oil companies when planning and training for oil-spill preparedness. We will now establish a robust local organisation in the north of Norway, based in Harstad. In addition to the new portfolio of oil-spill preparedness advisory services, DNV will provide advisory and verification services to the oil and gas industry. The new office will supplement

our existing maritime industry activities in Harstad,” says Ørbeck-Nilssen. Stein Thorbjørnsen, the general manager of NPS, established the company in 2006. “We’ve found a niche in the coastal and shoreline preparedness sector and have specialist expertise in planning and organising preparedness in addition to strategy and technology development. Our group of experts has also developed methods for analysing needs and creating user-friendly operational emergency plans. These are used by many of the Norwegian and international oil and gas operators,” he explains. “NPS will now be part of DNV and we can achieve a lot more together, including internationally where DNV is established in 100 countries. We also share the same values of quality, independence and expertise development,” says Thorbjørnsen. 

Photo: DNV/Håvard Nyseth

Oil and gas operations in the Arctic will require improved technology and new knowledge Oil and gas operations in the northern areas introduce several new risk elements; the distances are greater, the climate is cold, it is dark for a lot of the year and there may be no infrastructure. It is important that the safety level here is at least as good as in the conventional areas. Therefore, the Arctic conditions will require improved technology and new knowledge to reduce the likelihood of an accidental oil spill. In addition, efficient oil-spill preparedness solutions that reduce the consequences of a potential accident must also be put in place. “Both the industry and society focus heavily on reducing the environmental effects of operations in Arctic areas such as the Barents Sea. DNV wants to

offshore UPDATE NO. 2 2012 |

Gullfaks Subsea Compression

Assisting Statoil – Gullfaks Subsea Compression On Friday the 4th of May, the Statoil Board sanctioned the decision of proceeding with the Gullfaks Subsea Compression – GSC – project with an award of contract to be placed at Framo Engineering in Bergen for detailed engineering, construction and testing of a subsea gas compression manifold which will be installed and put into service on the Gullfaks South location in 2015.

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Hans-Erik Berge, Statoil CSM and BDL Materials Technology Bergen.

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This technological leap forward represents an important milestone in the efforts to improve recovery from this and other gas fields. For the Gullfaks field the investment decision means that the plateau production can be sustained for a longer period. The compressor system will boost the gas pressure before arriving Gullfaks C allowing for an increased production from the GFSAT 2 which after more than ten years of service is regarded as a mature field. The GSC will be the first wet gas compressor system ever that is put into service and will open up for a number of new business cases particularly for small gas fields with lower pressure or tail production from mature gas fields both in the NCS and worldwide.

Prior to the decision to proceed, the compressor (WGC4000) had to undergo an extensive technology qualification program (TQP) comprising full scale testing with HC-gas in a sophisticated test loop at Framo Engineering, Fusa, and endurance testing of more than 4,000 hrs running at numbers of different predefined operational conditions. Hans-Erik Berge, Statoil CSM and BDL Materials Technology Bergen, explains that DNV has assisted Statoil in the following main areas: ■■ Structural verification and HISC evaluation for the subsea cooler unit ■■ Fabrication follow up ■■ Trouble shooting

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Bård Espelid, BDL Subsea and Wells, DNV Stavanger.

Text: DNV Technical facts: Statoil

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Kristen Andrew Foshaug, Subsea Engineer, DNV Bergen.

■■

Documentation of condition after full scale testing

“The most challenging part of the DNV involvement was the HISC evaluation for the subsea cooler unit. Because of the complex geometry we had to perform a non-linear three dimensional finite element analysis in order to ensure that the subsea coolers were not prone to HISC. The high system temperature meant that this analysis had to be coupled to a thermal analysis in order to get the correct de-rating of the material”, says Kristen Andrew Foshaug, Subsea Engineer at DNV in Bergen. Bård Espelid, BDL Subsea and Wells,

Illustration: Statoil/ Framo Engineering

Gullfaks Subsea Compression

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Subsea gas compression manifold.

adds that “Managed from DNV in Bergen, the deliverables for the structural verification and HISC evaluation was based on a cross unit cooperation utilizing competence and resources from several units at Høvik and in Bergen.” Says Henning Bødtker, Statoil’s Material Lead for Gullfaks Subsea Compression; “During the engineering and construction phase of the TQP compressor and cooler, DNV has given a valuable contribution to the project with respect to design and material assessment, as well as follow up during fabrication. Being familiar with the design of the compressor system combined with thoroughly expertise within material technology, subsea design and fabrication

follow up, DNV should therefore be in the position to be able to give further contribution and assistance to Statoil during the execution of the GSC-project.” GSC Manifold System The GSC manifold system comprise two wet gas compressors including subsea coolers, gas mixers, power & utility systems and protection structure, and will be tied back to the L and M manifolds on Gullfaks Phase 2 installation delivering gas and condensate to Gullfaks C trough a 14 km bundle pipeline. The compressor design utilizes contra rotating impeller technology with each impeller shaft running at a maximum speed of 4,500 rpm. The gas that arrives

from the well heads on L- and M manifolds are prior to entering into the compressors, cooled in “tube-and-sheet” cooler units that are based upon free convection between gas in the cooler tubes and the sea water outside. The fact that the compressor system is fluid tolerant i.e. can handle liquid/ wet gas and thereby do not require any liquid removal (scrubbers, cyclones etc.), allows for a simplified process design of the compressor system. Both the compressor units and cooler units are designed such that they easily can be retrieved by applying a normal IMR vessel and be replaced by spare units during planned maintenance. 

offshore UPDATE NO. 2 2012 |

Structural well integrity

Structural well integrity project gathers pace In mid-2010, when a number of the world’s leading oil companies came together to begin a joint industry project (JIP) to develop structural well integrity guidelines, they turned to DNV as a project facilitator to undertake the day-to-day management of the project.

At the last count, there were over 800 subsea wells in the North Sea, many of them over 20 years old. As economic demands dictate that they are to be used for longer periods, regulatory bodies are seeking assurances that the wells’ condition and integrity are being correctly managed, particularly with regard to fatigue design and calculation methodologies. Because of this, it was decided to create for the first time a JIP to investigate aspects of structural well integrity. Initially, the Norwegian continental shelf was chosen as the geographic focus area due to the harsh conditions experienced there. However, it is a clear aim that the JIP results will be used as the basis for a recommended practice (RP) for the industry worldwide. The JIP was initiated due to the increased focus on documenting sufficient fatigue capacity in wellhead systems, particularly those on extended operation with large rig systems. Its objective is to address the drilling and well system integrity as a complete system. The intent is to develop recommendations for a uniform design philosophy to capture relevant structural integrity aspects – including seabed foundations, through the various wellhead system elements (steel and cement), downhole and BOP interfaces, riser systems to the rig connection. Guttorm Grytøyr, Principal Engineer, DNV Houston, says: “The need to develop recommended practices came from the industry itself, which recognised that there was no consistent overall design

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Photo: DNV

Text: Richie MagTaggart

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Guttorm Grytøyr, Principal Engineer, DNV Houston.

philosophy in place for drilling and well system integrity. As the facilitator of this JIP, we are pleased at the high level of involvement of leading oil companies and believe this will result in a robust set of recommended practices for structural well integrity.” The first task of the JIP was to provide RP guidelines on the overall design philosophy for drilling and well equipment – known as RP-1. The participants believe this philosophy will lead to reliable and safe designs; be convenient in use; help impose a known reliability level; and allow comparison of different designs for consistent reliability. A key element of the current Phase 1 of the JIP is to highlight gaps in present

standards and provide guidance on uniform design and analysis. As stated above, the JIP has initially focused on fatigue aspects, and the scope execution has been subdivided into design philosophy (RP element 1), fatigue (RP element 3), and integrity documentation management (RP element 4). The planned upcoming second phase of the project, RP element 2, focuses on the structural strength of drilling and well systems. It takes identified gaps into consideration and points out future needs, with the aim of developing a recognised and transparent method to obtain a consistent safety level across physical and contractual interfaces. RP-2 is currently under project definition. RP-3 concerns fatigue design and analysis – there is a particular focus on this subject because fatigue issues are less readily understood than other well integrity matters. Currently there are no specific international codes or standard relating to subsea wellhead fatigue assessments. Grytøyr continues: “The objective of RP-3 is to define a unified analysis methodology for assessing the fatigue damage to the wellhead system. This will provide the industry with an improved basis for assessing the structural integrity of the well and also for comparing the results for different wells and of different analyses. By using these results, we will be able to draw upon the current best practice in the industry and this is an important contribution to well integrity management.”

Photo: Statoil/Harald Pettersen

Structural well integrity

offshore UPDATE NO. 2 2012 |

Structural well integrity

The DNV Jip team

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Ole Rengård – Project Manager.

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Lars Tore Haug – project sponsor.

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Sofia Andersson.

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David Buchmiller.

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Torfinn Hørte.

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Jan Kingma.

Feedback and experience input have already been received from subsea wellhead suppliers, analysis firms, drilling companies and operators at workshops and meetings and through comments in document reviews. From this, the principles for a tiered approach have been agreed upon, according to which a level of refinement in the analysis can be selected based on the system’s characteristics. A basis for a benchmarking study has also been developed. The final element in the JIP concerns Structural Well Information Integrity

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Management (RP-4). Its purpose is to provide specific requirements to all companies participating in the JIP. It ensures that sufficient and trustworthy input is available to enable the application of all of the processes agreed on in RP-2 and RP-3. RP-4 recommends that operators establish, implement and maintain a system to manage their structural well integrity. Status To date, an overall design analysis methodology has been agreed on and is currently subject to an initial benchmark

study by selected analysis firms. This is part of the approach to turn the JIP deliverables into internationally recognised RPs. Early comments on draft documents (related to the RP-1, -3 and -4 sub-divisions explained above) have been received from the steering committee members and incorporated and endorsed for release to other stakeholders – including subsea vendors, rig owners and analysis firms – in the industry. To assist in this process, workshops have been held and attended by vendors, suppliers and operators to consider the various topics.

Structural well integrity

The JIP was designed to investigate aspects of structural well integrity. Initially, the Norwegian continental shelf was chosen as the geographic focus area due to the harsh conditions experienced there.

For the purpose of the industry consultations, these documents are now in the process of being issued as JIP Technical Reports. Based on the feedback, the intention is to convert and release the results of Phase 1 of this JIP as one RP (draft version – due to vital structural integrity aspects still pending and forming part of proposed activities for a Phase 2) covering design philosophy, fatigue analysis and information integrity management. It seems quite clear that the JIP will most likely proceed to Phase 2, where – in

addition to a continued focus on fatigue – structural strength aspects will receive priority attention. This will complete the picture, and warrant the subdivision or RP structure outlined above, i.e. a common design philosophy and information/integrity management supporting the updated analysis approaches for both fatigue and structural strength. Grytøyr concludes: “The project has received considerable interest from across the industry, indicating the significance of this JIP. By building a common

understanding of well integrity analysis approaches, such as input, timing and methodologies, between operators, rig owners and subsea suppliers, we will be able to define a set of valuable principles that can take the subsea industry forward in a safe and economically viable manner.”  The JIP partners Statoil (chair), BG Group, BP, Chevron, DNV, Eni, ExxonMobil, GDF Suez, Lundin, Marathon, Nexen, Shell, Talisman, Total and Woodside.

offshore UPDATE NO. 2 2012 |

Technology Qualification

Technology qualiﬁcation:

Recommended practice for subsea applications Developing new technologies is vital if the oil and gas exploration & production industry is to meet ever more challenging environmental requirements, but bringing these technologies to market in a timely manner relies on technology qualification (TQ). DNV has therefore brought all of its industry experience to bear on making the world’s best TQ standard.

Photo: Subsea7

Text: Richie MagTaggart

38 | offshore UPDATE NO. 2 2012

Technology Qualification

What is TQ? Qualification means “the process of providing the evidence that a technology will function within specific operational limits with an acceptable level of confidence” (DNV, 2011). New technology can either make a project possible or enhance its value. In either case, the operator needs to feel confident that the technology will perform as intended. The technology developer needs to build the operator’s confidence in the technology, as the operator bears the burden of convincing other project stakeholders to implement the new technology. As Martha Viteri, Technology Qualification Lead at DNV North America, explains: “It’s about building a structured process to develop a better product. Mainly, we are allying our experience to implement a process that is aligned with our risk-based recommended practice and will mature a product which is technically sound. We work with oil and gas operators and they see a lot of technologies from vendors. But until these technologies are in use, the operators don’t always know how safe the products are and how they will perform.

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definition-of-evidence processes and shows how to provide that evidence in order to build confidence in the technology in its service context. © DNV

Technology complexity drives the need for TQ For decades, new technologies – particularly for the offshore oil and gas industry – have been developed to allow oil companies to use floating installations and subsea facilities to produce in deeper waters. As technologies developed, new solutions were introduced and unknown service contexts were encountered so it became necessary to apply a systematic approach to qualify these new technologies.

››

Martha Viteri, Technology Qualification Lead at DNV North America.

Technology qualification builds confidence in the product and creates ways to ensure that a more robust technology is being installed offshore.”

The TQ Process – a systematic approach The TQ Process describes the activities and decision points for a specific product that are required to close technical gaps between the operator’s requirements and the available technology. The recommended work process in DNV-RP-A203 is summarised in the figure on next page.

The process is as follows: DNV’s involvement in the TQ success story Over the years, DNV has helped technology developers build this confidence by carrying out a systematic risk-based qualification process that clearly documents the technology’s performance and supports the integration of the new technology with project constraints such as costs, scheduling, risk and reliability. This was addressed by the issuance of a Recommended Practice (RP) – DNV-RP-A203 Qualification Procedures for New Technology (DNV, 2001) – which has been further revised in 2011. This RP has subsequently become an accepted industry practice and its recommendations have been adopted as the basis for company-specific requirements and procedures in the oil industry. The RP takes a risk-based approach to proactively identify the challenges and uncertainties of new technologies, and is intended for general application to any technology that might be developed in the future. It also provides a way of assuring

1. Qualification Basis and Technology Assessment The technology needs to be framed, determined and thoroughly described. Once that first step is completed, using the qualification process as a guideline, the next step is to determine what is new technology and why it is new technology. In the industry, this step is where engineers seem to be most challenged, according to Martha Viteri. The determination of whether a component or a system is new or modified influences how much more money and efforts have to be spent in order to get the technology ready for deployment. This milestone is critical when considering the schedule and cost of a new offshore development. However, knowing that the new or modified technology will boost revenue, it is worth ensuring that it will work as expected. Viteri also indicated that, based on experience, the investment in the

Subsea7; Reeled Pipe-in-pipe

offshore UPDATE NO. 2 2012 |

Technology Qualification

What is the technology and application to be qualified, how mature is it?

Qualification Basis Set the requirements

What is new about it?

Technology Assessment Novelty and show-stoppers

Qualification Plan Select qualification methods

How can uncertainties and risks be reduced for each and every failure mode? Gather data and results and document all that is done.

Execution of the Plan Collect evidence

Close out the gaps and make sure that the qualification expectations were met.

Performance Assessment Compliance w/requirements

Uncertainties and risks are reduced while confidence has increased.

All requirements met

Requirements not met or changing requirements

Milestone reached Requirements met

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Modifications

Threat Assessment Failure modes and risks

What are the failure modes and associated risks?

M*: milestone in qualification program

Technology Qualification Process flowchart (from DNV-RP-A203, rev. July 2011).

qualification of the new technology is marginal compared to the potential revenue and the confidence built in the product, and also to the potential consequences should the technology fail to perform. Some industry recommended practices, such as API 17N, have incorporated ways to facilitate the identification of a technology’s maturity and newness. However, it is important to understand that the readiness level of a technology is merely a categorisation, not a qualification process. A technology qualification process, such as DNVRP-A203, needs to be followed in order to “jump” from one technology readiness to another when several iterations are needed to get a technology deployment ready. 2. Threat Assessment and Qualification Plan This activity identifies failure modes and the risks that are relevant to the qualification of the technology. It challenges the concept and solutions by identifying

40 | offshore UPDATE NO. 2 2012

relevant failure modes with underlying failure mechanisms for the new technology elements. Potential failures are to be captured by: ■■ Compiling the system documentation ■■ Assigning baseline risk ranking criteria for the consequences and likelihood of the failure identified ■■ Identifying/assessing failure modes ■■ Highlighting critical failure modes & assigning key action items The outcome of this guided exercise must be a validated list of qualification activities intended to investigate the source of the potential failure so that it can be mitigated. It is recognised that there will always be a remaining risk, but the objective of this activity is to identify all potential threats to the technology. It is important in this step the participation of relevant experts in addition to a third party that has the proper experience in executing qualification processes.

3. Qualification Plan Execution and Performance Assessment Once the Qualification Plan has been created, it needs to be executed. Evidence is collected through experience, numerical analyses and tests. The purpose is to determine and document the performance margins for the failure modes of concern. The final and concluding element is the Performance Assessment. In this step, DNV and the qualification work team measure success by reviewing the available evidence against the original qualification targets, as well as by providing further confidence and removing any uncertainty between the evidence, failure modes and requirements of the Qualification Basis. Benefits of applying TQ Technology qualification is a process which quantifies the deployment-readiness of both internal and third-party technologies, and is a tool to quantify or move emerging technologies to a deploymentready state. Through its systematic approach, it: ■■ Provides a better understanding of a technology’s reliability and risk implications for a project and a platform in order to make risk-based project decisions (higher decision quality) ■■ Ensures the more efficient use of resources (reduced development cost) as well as increasing the likelihood of on-time delivery (reduces the time to market) ■■ Identifies failure modes and mechanisms ■■ Identifies design changes at an early stage (and thus creates an opportunity to improve the system design) ■■ Optimises qualification testing and analysis ■■ Uncovers interface issues between the manufacturer and sub-vendors ■■ Reduces the risk exposure by reducing uncertainties and increasing reliability ■■ Enables qualification efforts to be traced, and eventually allows quicker re-qualification for new operating conditions

Technology Qualification

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Electrically trace heated pipe in pipe. Courtesy of Subsea 7/ITP

Viteri concludes: “Technology Qualification benefits both operators and vendors alike. Very many technologies have been qualified by DNV since the RP A203 was first issued and this gives us insights into typical technology qualification challenges and pitfalls.” Case example DNV’s Qualification of Subsea 7’s and ITP’s Enhanced Thermal Performance Reeled Pipe-in-Pipe System and Reelable BuBi Lined Pipe System The recent qualifications of two new Subsea 7 technologies are among the many good examples of the subsea industry’s increasing acceptance of DNV-RP-A203. The DNV qualification process offers customers a rigorous review process with a focus on the novel aspects of the technology culminating in the issuance of a DNV Fit for Service certificate.

Enhanced Thermal Performance Reeled Pipe-in-Pipe System A fundamental aspect in many new deeper-water and more challenging subsea

Butting BuBi, mechanical lined pipe. Courtesy of Subsea 7/Butting

developments is how to maintain the appropriate product temperature within the pipeline infrastructure to avoid the formation of hydrates or waxing which would result in flow restriction and potentially a complete shutdown. To help address this, Subsea 7, together with ITP InTerPipe (ITP) has industrialized a reeled pipe in pipe system which can include electrical trace heating: the Electrically Heat-Traced Flowline (EHTF) – see top left illustration. The reeled pipe-in-pipe system with reduced pressure in the annulus, Isoflex™ insulation and ETHF offers the operator a product with an enhanced thermal performance reeled pipe-in-pipe system. The technologies involved (reel-lay and high thermal performance – which combines a thermal insulation system with low-power resistive heating elements) have both been qualified in accordance with DNV-RP-A203. The system was first qualified in passive mode (without heating elements), and subsequent qualification of the complete ETHF system with heating wires followed.

John Mair, Subsea 7’s Technology Director, commented: “the DNV-RP-A203 process provides a systematic approach for new technology development and qualification which is recognized worldwide within the subsea industry and adopted by Subsea 7 within their technology development process. Working with DNV has demonstrated a robust and consistent process in terms of planning, technical expertise and project execution.”

Reelable BuBi Lined Pipe System Subsequently, DNV was also involved in the qualification of Subsea 7’s Reelable BuBi® Lined Pipe System, which comprises a CRA liner mechanically bonded to the carbon steel pipe. The increasing demand for transporting corrosive media and the industry’s drive to develop lower cost pipeline systems have led to the development of the reeling of Mechanically Lined Pipe without any degradation of the pipes’ corrosionresistant liner. Subsea 7, in partnership with Butting, has developed the technology and skills to use the reel-lay method for the installation of the BuBi® mechanically lined pipe subsea without the occurrence of any wrinkling or other degradation of the corrosion-resistant liner. The technology has been fully qualified as Fit for Service following compliance with DNV-RP-A203. The tiered review of the qualification process with frequent interactions between Subsea 7, ITP, Butting and DNV ensured the early identification and resolution of any gaps in the TQ process for the Enhanced Thermal Performance Reeled Pipe-in-Pipe System and Reelable BuBi Lined Pipe System. Acknowledgements The authors would like to thank Subsea 7, ITP and Butting for their permission to publish this article. 

offshore UPDATE NO. 2 2012 |

VeriFIcation

Veriﬁcation of containment system risers DNV is globally recognised as a leading verification body in a wide variety of industries, including the offshore sector. Following the Macondo incident in the Gulf of Mexico in 2010, offshore operators have responded by developing offshore well containment systems and DNV has acted as the verification body for some of these systems.

The offshore industry is subject to strict requirements imposed by operators as well as government authorities to ensure safety, environmental and other relevant demands are met. Products and systems therefore often undergo third-party verification to ensure all relevant requirements are met. The scope of work for verification is ultimately determined by the customer or national authorities on whose behalf DNV carries out the verification. After verification, DNV generally issues a verification report or a Statement of Compliance. DNV’s verification of containment systems may include: ■■ A transparent, global, risk-based and fully independent approach to verification and quality assurance – thereby increasing the likelihood of successful design, fabrication, deployment and safe in-service operations. ■■ The verification of compliance with regulatory requirements. ■■ Independent verification throughout the entire life cycle of the containment system: from concept to commissioning, storage and deployment in response to an incident. DNV is well positioned to do verification due to its technical expertise, its reputation as a highly respected and reliable third party and its codes and standards,

42 | offshore UPDATE NO. 2 2012

Text: Richie MagTaggart

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Gustav Heiberg, Head of Department, Deepwater Technology, DNV Oil & Gas North America.

which are recognized and applied worldwide. Gustav Heiberg, Head of Department, Deepwater Technology, DNV Oil & Gas North America, says: “DNV provides risk based verification in a foreseeable and transparent way while enhancing communication between involved parties. Our involvement – including reviews, inspections and other verification activities – can be at any time from the design phase to the installation and commissioning phase of the system to be verified.” The aim of DNV’s verification services is to create confidence in products and systems in a cost-efficient manner. The

verification provides added value by checking high-risk elements at an early stage in a product’s development and continuously throughout the project and whilst the product is in service. DNV’s transparent and independent approach to the verification of offshore systems and facilities, from the design to the operational phases, helps reduce and manage risks, thereby ensuring successful subsea projects. Verification work – which DNV undertakes worldwide – may be driven by the authorities, such as in the United States, Australia or Trinidad & Tobago, or integrated into the company’s culture or practices. Extensive verification work has been carried out in the Gulf of Mexico. However, an increased focus on and awareness of the need for third-party verification has been noted since the Macondo incident. Why verification? Verification gives stakeholders and regulatory authorities the required confidence that projects have been implemented right first time. DNV’s independent and competent appraisals provide assurance that offshore facilities have been designed, constructed and installed in accordance with project objectives. DNV strongly believes that an open approach to the thoroughness and level of involvement in verification tasks enables owners and contractors to reduce risk at

VeriFIcation

optimum cost. Partha Sharma, Head of Section, Riser, Umbilical, Mooring and Pipeline, DNV Oil & Gas North America, says: “We recommend starting verification activities as early as possible, ideally during the feasibility and conceptual design phase. In the early phases, changes can be made with minimum cost and schedule impact.”

important to ensure that all the required parts of the system are available at all times. ■■ To ensure the long-term performance of the system – in the event of its deployment – procedures for preservation, required testing and long-term storage onshore need to be developed. ■■ In the case of an incident, it is generally uncertain what vessels will be available to install and operate the system. ■■ Deepwater containment systems are in so far as possible made up of proven technologies. It is, however, important to qualify any new technologies as well as technologies used for new applications. 

Photo: Statoil/Øyvind Hagen

Specific Points for Containment Systems The containment system is important to the US government when granting any permits to drill new wells in deep waters in the Gulf of Mexico. DNV third-party verification can help confirm that the system is ready for deployment.

Containment systems have some aspects that need to be considered in the verification process: ■■ The response time is crucial to how effective a containment system is in terms of limiting the consequences of a subsea release. ■■ A containment system is designed to be deployed and be effective in a wide range of conditions. Due to the urgency involved when it is deployed, as much design work and procedure development as possible should be done beforehand. ■■ A system is made up of a large number of components that will be stored. It is

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Oseberg Field Centre.

offshore UPDATE NO. 2 2012 |

Addressing Deepwater Lifting

Addressing deepwater lifting Present and future deepwater field developments will put more and more focus on safe lifting operations. And, as oil and gas exploration and development move into deeper water, the risks related to lifting operations are increasing.

Background The development of subsea cranes and lifting appliances has been driven by constant demand for increased lifting capacity, operations in greater water depths and motion compensating systems. This has introduced several technological challenges related to ensuring the reliable execution of subsea lifting operations so that objects can be safely placed on and removed from the seabed. Ensuring proper design and correct operation, as well as regular inspection and maintenance, are crucial not only for the reliability of a lifting appliance, but also for the safety of the personnel and equipment involved. Lack of Standard Subsea lifting standards and regulations have not followed the steep curve of technological progress. “The

While various safety functions are in use, implementing standards and regulatory requirements is the safest and most efficient way of reducing the risks involved in offshore operations.

Photo: DNV

“Existing standards and regulations don’t sufficiently meet this challenge and this is why DNV has initiated a joint industry project to ensure a unified safety approach,” states Robert A. Oftedal, DNV’s Business Development Leader in Cranes & Lifting. Sixteen key international offshore players have joined the project.

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Project sponsor Robert A. Oftedal, Business Development Leader and Senior Principal Engineer.

required safety level has been defined by clients’ specifications, technological boundaries and manufacturers’ considerations, rather than regulatory documents acknowledged by all the stakeholders involved. Some client specifications may also be based on vessel-to-platform lifting and not subsea lifting. This situation is a challenge when contracting new equipment,” Oftedal explains.

Facts • The need for energy is continuously increasing in the world. • One of the solutions for the growing energy demand is deepwater oil and gas field exploitation. Such development introduces several technological challenges, among them ensuring safe execution of subsea lifting operations. • Many fields are already discovered in deep waters. • There will be hundreds of subsea field developments worldwide in the next few decades, many in very deep waters. Deepwater field developments worldwide must demand high focus on safe execution of lifting operations, both in the installation phase and throughout the lifetime of the field.

44 | offshore UPDATE NO. 2 2012

DNV’s Role DNV invited the industry to develop a unified approach concerning important aspects of subsea lifting. The following firms have so far joined the project to accomplish this objective: Statoil, Petrobras, Lundin Norway, Marathon Oil Norge, Technip, Subsea7, SAIPEM, Heerema Marine Contractors, Cargotec, Liebherr Werk Nenzing, TTS Energy, Huse Engineering (Rolls-Royce), SamsonRope, W. Giertsen Services, ExxonMobil and Ernst-b. Johansen (Cranemaster). The budget is 5.9 million NOK. Project Goals Reducing risks and improving consistent industry practice in the area of deepwater lifting is the technical challenge being met by this project team. The aim is to increase the efficiency and safety of related equipment design, operation and maintenance. Conclusions on a Recommended Practice are anticipated spring 2013. 

Project sponsor Robert A. Oftedal, Business Development Leader and Senior Principal Engineer – Master of Science, NTNU Trondheim, Marine Engineering/Naval Architecture, 1987 Robert A. Oftedal has more than 20 years of experience and started his career by working with hydrodynamic and structural analysis for floating structures. He took on the role as Head of Section for Cranes & Machinery in 2004 followed by management of the merging of the crane/lifting competent groups in Bergen and Stavanger into one large section. In his current position as Business Development Leader he is focusing on identifying new possibilities for growth within complex cranes and lifting appliances.

Photo: DNV/Magne A. RĂ¸e

Addressing Deepwater Lifting

offshore UPDATE NO. 2 2012 |

safety approach

The next generation safety approach post Macondo DNV is committed to helping further enhance safety in drilling and well operations. As part of our efforts here, DNV this year launched an internal R&D programme focusing on some of the important challenges. This article gives a high-level overview of the programme’s focus areas and provides some insights into our ongoing work on Well Control Philosophy, particularly addressing the automation of some BOP functions. Text: KRISTEN ULVESETER AND PEDER ANDREAS VASSET, DNV

Background The Macondo accident in 2010 and the Montara blowout in Australia the year before were a revelation to the industry and society at large, and reminded us all that major risks are involved in drilling for hydrocarbons and that loss of well control could lead to major disasters for both the crew and environment. Following these accidents, the regulators and industry had a need to understand their causes in order to initiate actions/improvements that would be effective in helping minimise the risk of similar accidents happening again. Numerous investigations and activities were initiated both inside and outside the US, focusing on analysing the ■■ causes/events leading up to the disasters ■■ efficiency and adequacy of safety regulations and practices applicable to offshore drilling.

The findings have since initiated updates in regulations and practices, and the industry has ongoing activities addressing how to better control and minimise risk going forward. Since the Macondo accident, DNV has supported investigations, provided guidance and support in some of the ongoing industry improvement programmes/initiatives

46 | offshore UPDATE NO. 2 2012

and initiated Joint Industry Programmes, e.g. relating to Structural Well Integrity. At the start of 2012, DNV also launched an internal R&D programme relating to Drilling & Wells called the Next Generation Safety Approach. In this internal programme, we focus on ■■ proposing better risk analysis methods that make use of existing risk models combined with online data, thus providing better operational decision support as it is needed ■■ Well Control Philosophy ■■ Well Integrity Management ■■ Environmental Emergency Management Some of the outcomes of these internal activities could involve the stimulation of Joint Industry Programmes, updating of DNV standards and improved knowledge regarding technical, organisational and operational barrier management and control. In this article, we provide an outline of one of the projects under the part programme called Well Control Philosophy. Some highlights: In offshore drilling today, well shut down is initiated by human action. We ask; is this an adequate and robust approach for the future?

As drilling operations are becoming more complex and challenging, it is, in our view, time to look at current safety systems and well control philosophies on drilling rigs. The BOP system has received much negative attention in the media over the past few years. This is believed to come partly from a general misconception that the BOP is an emergency backup system. Erroneous expectations may lead to the belief that, if all other systems for controlling the well fail, the BOP will close the well no matter the situation. In reality, this could have been the case if the blowout preventer had been designed to be a ‘blowout arrestor’. However, the current design criteria for BOPs do not address ‘blowout arrestor’ scenarios. Therefore, we cannot assume that a BOP designed according to current standards is in fact able to stop a blowout that has been initiated. Therefore, the usefulness of the BOP is dependent upon correct use, i.e. that the BOP system is used in accordance with its designed intention and specification. This means that the BOP must be activated before the blowout in order to prevent it. The BOP functions have remained unaltered for decades and any activation

Photo: Getty Images

safety approach

of the BOP system is done by responsible personnel only. In deep waters, well kicks can be difficult to detect and small well kick volumes passing through the BOP before they are detected are more likely to occur here than in moderate and shallow water depths. A highly compressed undetected gas kick that enters the marine drilling riser can cause considerable problems as it expands and replaces large volumes of mud. DNV is currently in the process of evaluating how the human operator may best be supported in a well control event in order to ensure that correct actions are taken in time. The human role and

the human-machine interaction are being considered, as are improvements to technical solutions, such as automating some BOP functions. Automated drilling operations are expected to increase drastically over the coming years and automation of the BOP system is also possible, but the efficiency of this will rely on early and accurate kick detection. High-level pressure control is required for marginal formation-pressure limits, so an efficient and reliable kickdetection system is especially important. The quality and processing of the information flow will also be imperative and the automated functions will depend on

the scenario, i.e. ongoing operations, mud-balance system, well-control system configuration, drill-string configuration, etc. The person responsible for drilling will still be obliged to manually activate the BOP as before if a kick is detected, but in addition the system can be designed to activate certain BOP functions if the manual activation is not performed. The results of the work of evaluating the human role, human-machine interaction and potential to automate some BOP functions will be presented to the industry as a guideline currently scheduled for release at the end of 2012 or early 2013.Â ď&#x201A;Ł

offshore UPDATE NO. 2 2012 |

CO2 storage

DNV KEMA launches a new certification framework for CO2 storage Carbon Capture and Storage (CCS) is the only technology available to mitigate large-scale greenhouse gas emissions from both fossil-fuel-based power generation and gas cleaning operations, both onshore and offshore. DNV KEMA considers CCS to be a strategically important technology for upholding sustainable growth whilst reducing carbon dioxide (CO2) emissions. Text: MICHAEL E. CARPENTER, DNV KEMA

Safe, reliable and long-term storage of captured CO2 in geological reservoirs is a prerequisite for CCS and yet remains a key uncertainty affecting widespread deployment of the technology. In fact, the lack of a common international method for CO2 storage site selection, risk assessment, monitoring and verification was highlighted by the International Energy Agency in its 2009 Technology Roadmap for CCS and such a method was seen to be a crucial building block for the CCS industry. The importance of such an internationally recognised process has become more critical with the recent inclusion of CCS under the Kyoto Protocol’s Clean Development Mechanism (CDM). How can project developers, regulators and the public be assured that underground storage of CO2 is safe, predictable and commercially viable over the long term? DNV KEMA believes the answer to this question lies in a new certification

48 | offshore UPDATE NO. 2 2012

framework for CO2 storage sites that is designed to mitigate these uncertainties through a site-specific and risk-based approach to site selection, monitoring and verification. Certification framework The new framework builds on preceding DNV KEMA guidelines for CO2 storage and is organised as two distinct documents to ensure clarity. The first document is Recommended Practice (RP) J203 for the selection, qualification and management of geological storage sites. The second document is DNV Service Specification (DSS) 402, which defines the following statements and certificates that may be issued in accordance with the RP at successive stages of the project development: ■■ Statement of Feasibility ■■ Statement of Endorsement ■■ Certificate of Fitness for Storage ■■ Certificate of Fitness for Closure.

The new framework builds on five years of development work with industry and regulators that took the form of Joint Industry Projects and resulted in the publication of the CO2QUALSTORE (2009) and CO2WELLS (2011) guidelines. The content of both these guidelines has now been streamlined and collated into RP-J203, which will be actively maintained by DNV KEMA to take account of industry developments. A key intention of RP-J203 is to harmonise the implementation of CO2 geological storage in compliance with regulations, international standards and directives. To achieve this, the RP outlines generic workflows reflective of a site-specific and risk-based approach that, if followed, should contribute to enhanced traceability and efficiency across projects. RP-J203 is consistent with the ISO31000 international standard for risk management and DNV KEMA has drawn on the body of technical

CO2 storage

›› Schematic diagram illustrating some of the well integrity issues that are addressed in the new DNV KEMA certification framework for CO2 storage sites. The framework is applicable on a global basis, onshore as well as offshore. © DNV and Norwegian Petroleum Directorate (NPD).

and regulatory experience within the upstream oil and gas industry throughout the development process. About DNV KEMA DNV KEMA Energy & Sustainability is a global authority in business and technical consultancy, emissions reductions, certification and risk management across the energy value chain.

In a world of increasing demand for energy, DNV KEMA has a major role to play in ensuring the availability, reliability, sustainability and profitability of energy and related products and processes. We combine unique expertise and facilities in order to add value to our customers in the fields of risk, performance and quality management.

With over 2,300 experts in more than 30 countries around the world, DNV KEMA is committed to driving the global transition towards a safe, reliable, efficient, and clean energy future. DNV KEMA is one of three companies in the DNV Group, alongside DNV M aritime and Oil & Gas and DNV Business Assurance. 

offshore UPDATE NO. 2 2012 |

horizontal drilling

Recommended practices for onshore and shore approaching horizontal directional drilling projects

HDD in Practice HDD installations have been completed in nearly every conceivable subsurface condition. They are also being utilized increasingly in the shore approach of offshore pipelines, primarily because they present a lower environmental impact in certain cases than alternative construction methods. In contrast, shore crossing installations using HDD are much more complex and challenging than typical surface to surface installations. Many factors determine the success of an HDD project, and all are under evaluation for the new requirements and recommendations. Existing guidelines have failed in establishing clear parameters, limits and criteria for essential issues related to HDD projects. DNV’s current work fills a void and offers a solution in this important area. Project Objectives Our objective is to elaborate a set of requirements and recommendations in order to guarantee the quality of an HDD project and the success of HDD operations. All relevant aspects in an HDD project are being addressed to ensure that site investigation, engineering, planning and execution of pipeline installation by HDD are performed in accordance with minimum requirements and best practices.

50 | offshore UPDATE NO. 2 2012

Horizontal directional drilling (HDD) is an alternative construction method in the trenchless industry that has experienced rapid growth in recent decades. It represents a significant improvement over traditional open cut methods for installing pipelines beneath obstructions such as rivers, highways, railroads and other obstacles. However, HDD is a complex procedure not well understood by most contractors. This 2011 joint industry project (JIP) engages DNV with the affected industry. The result will be a set of internationally acceptable requirements and recommended practices for HDD construction.

“This is an ambitious project, but we are confident that the objectives will be accomplished resulting in many benefits to the participants and industry.” Danilo Machado, Project Manager

Joint Industry Project This is the first time operators, contractors and drilling companies have joined to discuss best practices and minimum requirements for successful pipeline installations by HDD, keeping in mind not only important issues related to the borehole but also aspects related to the pipeline to be installed. The resulting standards will provide first-time company benefits: clear guidance on HDD projects, and a reduction in the risks and costs of HDD works. The project started in May 2011, internationally recognized drilling companies joined the project and today there are 11 participants and HDD specialists with several years of experience in many projects worldwide. 

Many problems have been faced in HDD operations: the industry is aware that there is a long-term benefit when they invest in the development of application standards and designs for techniques that will provide a successful job and specify the acceptable range of conditions. That is the idea of this JIP – our first JIP in Brazil.

For more information, please contact: Danilo Machado, Surf & Pipeline Section, Rio de Janeiro, Brazil danilo.machado@dnv.com

ÂŠ iStock

horizontal drilling

offshore UPDATE NO. 2 2012 |

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.