oil and gas update 0113 tcm4-549016

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News from DNV to the oil & gas iNDustry No 01 2013

oil & gasupdate

CaN arCtiC risk be maNageD?

flNg Comes of age

New reVisioN of DNV’s isDs staNDarD

DNV eNhaNCes offshore Class rules

integrated barrier risk management

the power of joining forces – several new JiPs launched

shale gas risk management

2 | oil & gas uPDate NO. 1 2013

cONteNts

DNV enhances offshore class rulesJiP: Vortex-induced motion study for deep draft semisubmersibles

shale gas risk management: the importance of being trusted

›› ››››

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Published by DNV maritime and oil & gas Communications

editorial committee: Cathrine torp, svein inge leirgulen and kristian N. lindøe Joyce Dalgarno, editor Design and layout: Coor media 1304-001 Front cover: luoman / getty images

Please direct any enquiries to [email protected]

Online publications: www.dnv.com/industry/oil_gas/publications

DNV (Det Norske Veritas as) No-1322 høvik, Norway tel: +47 67 57 99 00 © Det Norske Veritas as www.dnv.com

oil & gas update

To view this update in PDF format on your tablet, scan the QR code or go to www.dnv.com and download the PDF manually.

www.dnv.com

More control – better safety ............................................................................ 6

The power of joining forces ............................................................................ 9

Subsea forgings JIP – a win–win for the industry ........................................ 10

Elevating the industry to a higher level ....................................................... 11

Determining a more accurate vortex-induced vibration (VIV) assessment of complex jumpers .................................................................... 12

Vortex-induced motion study for deep draft semisubmersibles ................ 13

Improved design, analysis and testing of umbilicals ................................... 14

Stimulating investment in energy efficiency measures ............................... 15

DNV enhances offshore class rules ............................................................... 16

Free choice of class for floaters in the Gulf of Mexico – DNV is chosen .. 18

New class notation for seismic vessels .......................................................... 19

Well capping technology at your service ...................................................... 20

A new revision of DNV’s offshore standard for Integrated Software Dependent Systems ........................................................................................ 21

HHI changes approach to systems and software on semi-sub newbuilding ................................................................................................... 22

Shale gas risk management: the importance of being trusted .................. 24

FLNG – an old idea comes of age ................................................................ 27

DNV to class PETRONAS FLNG Unit, expected to be the world’s first in operation ............................................................................................ 29

Can Arctic risk be managed? ........................................................................ 30

DNV and Statoil cooperate to enhance Arctic competence ....................... 34

DNV launches a design framework for floating structures in ice .............. 35

News .................................................................................................................. 4

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oil & gas uPDate NO. 1 2013 | 3

eDitOrial

The offshore oil and gas industry is moving into remote regions with harsh environments, chal-lenging reservoirs and ultra-deep waters that often imply environmentally sensitive areas. It is only by developing new approaches, technolo-gies and practices that many fields will become accessible with acceptable costs and risks.

Wherever oil and gas discoveries take us, safe and responsible operations are always the num-ber one priority. Whilst we have seen improve-ments in occupational safety in the oil and gas industry, major accidents still occur. Barrier-based risk management approaches, often asso-ciated with bow tie diagrams, are increasingly being used as the primary operational tool to address major accident events. In this issue of Oil & Gas Update, we highlight the importance of the bow tie tool, and outline the real benefits it can bring if properly used.

At DNV, we recognise the advantages of work-ing together with partners to develop new tech-nologies, methodologies and solutions. We are continuing our tradition of collaborating and present several Joint Industry Projects (JIPs) in this Update. These include a forging-material JIP to improve the quality, cost and delivery times of forgings for the subsea industry; a JIP on how to maintain and inspect jacking gears; one on how to treat increasingly complex jumpers; another on developing best practices for quantifying vortex-induced motion on deep draft semisub-mersibles; one looking into how increasingly complex and valuable umbilicals perform over

time; and finally the Energy Efficient Offshore Partners JIP, which involves offshore support vessel owners and charterers and aims to reduce fuel consumption.

Being in the forefront of delivering relevant and comprehensive solutions and services is a key part of DNV’s mission. To this end, we are continuously developing and enhancing DNV’s standards and guidelines. A prime and exciting example of this is the launch of DNV’s enhanced and restructured offshore classifica-tion rules for Mobile Offshore Units. The new rules include a comprehensive description of interpretations, making the rules’ requirements easy to understand and apply throughout the design, construction and operation of the asset. For the shale gas sector, DNV has issued a Rec-ommended Practice (RP) for the entire lifecycle of shale gas extraction based on risk manage-ment principles. Meanwhile, DNV and key indus-try players have developed an enhanced design framework for floating structures in ice-covered Arctic waters.

DNV has grown to become a think tank, R & D partner and key risk assessment and manage-ment organisation within the global oil and gas industry. We thrive on working closely with our customers. Sharing knowledge and experience is paramount for achieving the best possible results, and we will continue to do so in our pursuit of providing safe and reliable solutions to complex projects in challenging operational environ-ments.

time for collaboration and new approaches

Peter Bjerager Director of operations, DNV North america oil & gas


DNV’s Deepwater Technology group in Houston is working with Williams Field Services (Williams) on the materials verifica-tion, fabrication and installation phases of the Tubular Bells Export Pipeline project in the Gulf of Mexico. DNV is providing Wil-liams with independent, third-party verifica-tion support.

Williams is constructing a 16-mile export pipeline system for the Tubular Bells field in the Gulf of Mexico. This pipeline will transport oil and gas from the future Gulf-star FPS™ SPAR to the existing Blind Faith export pipeline system located in Block MC-728. DNV is verifying the design, fabri-cation and installation of the pipelines, pipe

line end manifolds (PLEMs) and jumpers. Since the contract was initially awarded,

the scope of work has expanded to include the design review for risers, valve-procure-ment inspection services and inspection of a marine load in Wakayama, Japan. Addition-ally, DNV now serves as the certified verifica-tion agent for the fabrication portion of the Titanium Tapered Stress Joints (TTSJs).

“DNV has been able to fill various roles throughout Tubular Bells’ verification, fabrication and installation processes,” said Miguel Urias, DNV’s project manager. “In cases such as these, where DNV is advocat-ing industry best practices, we are able to provide our customers with independ-ent verification of all components during the design, construction and installation phases. This also safeguards the customer’s interests.”

The expected completion date for the construction of the pipeline is December 2013.

Statoil has awarded DNV the design verifi-cation contract for its Aasta Hansteen Spar FPSO, which will be the world’s largest Spar platform and the first of its kind on the Norwegian continental shelf (NCS).

The Aasta Hansteen field development is presently one of the most important developments in Norway and a pioneer in the deepwater (1300m) and harsh environ-ment sector. This is the first Spar on the NCS and also represents new technology for Statoil on a number of items, such as fibre rope mooring, steel catenary risers and the fact that the Spar is the largest of its kind.

A key task for DNV will be to check that NORSOK requirements are adequately implemented in the Technip Houston design and that the new technology is documented to be safe.

As well as the design verification scope, the contract includes a Structural Integ-rity Failure Risk Assessment covering all phases of the project. Production start-up is planned at the end of 2016.

DNV in North America has been awarded a USD 3 million US Department of Energy funded RPSEA (Research Partnership for Securing Energy for America) project to evaluate and support the development of two cost-competitive dry-tree semi-submers-ible rig concepts for the Gulf of Mexico. The rigs will have drilling and production capabilities and be located in minimum water depths of 8,000 feet.

DNV is to act as an independent third party to evaluate the concepts’ maturity levels and define the further development scope based on critical design issues and the management of these. Approval in principal of the concepts’ performance and qualification of the riser tensioner technology are included.

Prior to this project, DNV has worked with Deepstar to mature these concepts.

“We’re drawing on all of DNV’s interna-tional deepwater and technology knowl-edge, bringing it to Houston for the benefit of the local industry and to help develop floater concepts for the Gulf of Mexico,” says Jenny Lu, DNV head of the project.

DNV to evaluate two dry-tree semi-submersible rig concepts for use in ultra-deep us waters

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aasta hansteen verification contract awarded to DNV

Verifying williams’ tubular bells project


>> terry loftis, transocean’s Director of engineering, has been appointed as the Chairman of DNV’s global rig owners’ Committee.

News

DNV has won a contract with Total for the classification of a tension leg plat-form (TLP). DNV’s office in Houston will carry out the work. The Moho Nord Phase 2 project will use a TLP with a hull of around 9,000 tonnes and topsides of 5,000 tonnes. The platform will be located offshore Congo on the west coast of Africa. The TLP will be installed at the Moho Nord field in the first half of 2015 with first oil due in 2016. DNV has been involved since the early concept develop-ment phase and has also helped Total with extensive independent verification to provide confidence in its first TLP Project. DNV’s overall technical competence and experience with TLPs were a key factor in winning this contract.

Classification of total’s moho tlP

New Chairman of DNV’s rig owners’ Committee appointed

Terry Loftis, a veteran of the industry and Transocean’s Director of Engineering, has been appointed as the new chairman of DNV’s prestigious Rig Owners’ Com-mittee. The members of the Rig Owners’ Committee represent owners and manag-ers of mobile offshore units (MOUs) and floating production units. The committee is intended to provide an active forum for the industry to share and discuss current and future developments in technology and practices, and support initiatives that will benefit the industry.

The functions of the committee also include providing industry input to DNV’s current and future activities, including DNV’s innovation programmes, industry initiatives and rule-making process. While DNV updates the industry on its activi-ties at committee meetings held annually in Houston, Aberdeen and the UAE, the committee typically offers feedback on the quality and scope of DNV’s services related to floating drilling and production units.

Mr Loftis’s technical involvement with

MODUs began when he was an independ-ent consultant for Transocean working on the design and construction of semi-sub-mersible drilling rigs in the mid-1980s, and he joined Transocean in 1997. After being actively involved in the design and con-struction of several ultra deepwater drill-ships in Korea, he returned to Houston to lead the Dynamic Positioning & Controls group within Transocean Engineering until he was appointed to his current position as Director of Engineering.

DNV and Korea Gas Corporation (KOGAS), Korea’s national gas company, have entered into an agreement to coop-erate on a feasibility study on the estab-lishment of an LNG bunkering infrastruc-ture in Korea. This is one of the largest and most comprehensive feasibility studies ever initiated in the worldwide LNG bun-kering industry.

DNV will qualitatively and quantita-tively study the feasibility of implementing

LNG bunkering in ports in the south-eastern area, Pusan, and western area, Incheon and Pyeongtaek. This project will be led by Dr Sun Il Yoo, Senior Customer Service Manager in DNV Korea, who will be assisted by the DNV Clean Technology Centre in Singapore.

Through this project, DNV aims to define Korea’s commercial opportunities related to LNG distribution and ship-ping by addressing possible LNG supply chains and infrastructures, LNG shipping technologies and bunkering, standards, regulations and issues regarding public acceptance.

DNV to cooperate with korea gas Corporation on a feasibility study of lNg bunkering in korea

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OFFshOre saFety

More control – better safetyIntegrated barrier risk management

many companies in the offshore oil and gas sector are starting to use barrier-based risk management approaches as suggested by the international association

of Drilling Contractors (iaDC) in its hse Case guidelines. however, this is sometimes seen as an isolated, one-off activity which is useful for regulatory

purposes and not much more. that means missing out on a great opportunity.

TEXT: Robin Pitblado, DNV

The barrier approach uses the bow tie risk model as its under-pinning. This sets out in a simple figure the Hazard, the Top Event (i.e. the undesired loss of control or leak event), the Threats that cause this and the Consequences that might arise. In between the Threats and the Top Event are the Prevention Barriers – those con-trols (or controls and safeguards) which stop a threat from propagating through to the top event. Similarly, between the Top Event and the Consequences are Mitiga-tion Barriers which reduce the magnitude of the potential consequences. This figure is usually extended to depict Barrier Decay Mechanisms (or escalation factors), which show how the main pathway barriers can degrade and what specific controls are put in place to prevent this (e.g. training, competence, inspection, preventive main-tenance). The figure is often enhanced using colour coding to show which group is responsible for each barrier (operations, maintenance, corporate, contractors, etc).

Many operators develop a collection of bow ties for their major activities – typically 10-20 – and when built-out fully these define all the major controls deployed to make the offshore facility safe and protect against environmental spills. The bow tie

diagrams are shared with staff and contrac-tors for training purposes and with regu-lators to demonstrate safe control. Bow Ties are the primary operational tool that addresses major accident events and how staff and contractors can manage these safely.

DNV views this as a basic implemen-tation of bow ties and as not at all extract-ing their full potential. In the overall con-text of risk management, at design time DNV sees a mix of tools as being necessary – regulatory and classification compliance tools as well as both qualitative tools (e.g. HAZID, HAZOP) and quantitative tools (e.g. CFD consequence modelling and

quantitative risk assessment (QRA) – to better define risks and risk management. But these are not so useful for operations and this is where the Bow Tie tool, if prop-erly managed, can provide real benefits.

oPeRational Risk ManageMent using bow ties The first step is to bud the bow ties and share them. This requires:■■ Building the bow tie diagrams■■ Clearly assigning responsibility for all barriers

■■ Verifying that there are sufficient barri-ers in place for all threats – more barri-ers for higher risks, fewer for lower risks

The above set of barrier definitions is good, but on-going performance monitor-ing is better and more powerful. Barriers degrade over time if not looked after and bow tie diagrams can become fiction if not actively managed. Ideally, companies would like near real-time status on each barrier in order to be able to manage their activities safely. Some companies have developed documents that specify the barriers that must be functioning for every planned activity – this recognises that barriers have holes and some may be

›› robin Pitblado, Director she risk management

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OFFshOre saFety

degraded. This is sometimes called the Manual of Permitted Operations (MOPO) or Statement of Operational Boundaries (SOOB). A problem here is knowing what barriers have been degraded. Inspection, preventive maintenance and audits are all good techniques but have a cycle time that can allow a year or more between status updates.

A novel method, developed by DNV, provides much more frequent updates on the barrier status – the BSCAT accident investigation approach. In short, BSCAT is the barrier-based extension to DNV’s SCAT (Systematic Cause Analysis Tech-nique) method. Every incident means that some barriers have failed, and since many facilities experience over 100 actual or near-miss events annually, analysing these for barrier failures can provide the most frequent and up-to-date barrier status. It turns out this is not much more work than

routine investigations and it reinforces the risk assessment supervisors and staff for every incident. Since demands on barriers are now identified as amongst the most useful leading indicators (e.g. API 754 and OGP 456) and many companies are com-mitted to adopting these standards, the BSCAT approach and bow tie risk man-agement integrate powerfully into these systems.

ConClusions The offshore oil and gas industry is start-ing to use bow tie risk management for operations, but so far the use is mainly for regulatory purposes and thus does not extract the full value from the approach.Ongoing performance monitoring is key and that means tracking the performance of all barriers to make sure they are func-tioning adequately. This helps to ensure that all the necessary barriers are function-ing when activities are carried out, espe-cially less frequent ones. The DNV BSCAT approach is an important element of this and it also provides data to feed into the new system of leading and lagging indica-tors being adopted in the industry.

Put simply, more control (i.e. under-standing what controls are deployed and their operational status) equates to better safety.

the offshore oil and gas industry is starting to use bow tie risk management for operations, but so far the use is mainly for regulatory purposes and thus does not extract the full value from the approach.

Hazard

TOP EVENT

Consequence 1

No ignition

Consequence 2

Ignited – Jet fire

Cause 1

Corrosion

Cause 2

Mal-operation

Barrier decay mechanism

EFFECTS

Barrier decay mechanism

Elimination Prevention Detection Mitigation Emergency

Barrier decay mechanism controls

Barriers to eliminate & prevent causes of

hazardous eventBarriers to control

consequences & effects

Loss of containment

Risk management hierarchy

e.g. flammable gas

Barrier decay mechanism controls

THR

EATS

›› figure 1: example of a simplified bow tie diagram


OFFshOre saFety

DNV maintains records of oil, gas and petrochemical industry safety performance and these show that the industry has been tremendously successful in reducing occupational-related accidents, but has been much less successful for major accidents. occupational accidents have fallen by an average factor of 3 in the past 10 years and nearly a factor of 10 in the

past 20 years. Conversely, there has not been any decline in inflation-adjusted major accident claims as compiled by marsh in its 100 largest losses list. DNV believes that the methods which have delivered the great improvements in occupational safety are not appropriate for achieving a reduction in major accidents and that is why there has been so little improvement. an exception has

been in the North sea, where major accident rates (as indicated by large leaks) have significantly declined. the difference between the North sea and other places is the focus on barriers and barrier management and ensuring that barriers are maintained at their specified performance standard throughout the facility’s lifetime.

›› figure 3: occupational vs major accident performance. ›› source: m&m’s 100 largest losses to 2011. includes refining, Petrochem, gas processing, terminals, upstream.

1972–76 1977–81 1982–86 1992–96 1997–01 2002–06 2007–11

$1,000

$0

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$Billion

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Total loss per 5 yrs

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APIBPChevron TexacoConocoPhillipsDowExxonMobilShell Concawe

1994 1996 1998 2000 2002 2004 2006 2008 2010 2012

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Occupational Safety Performance

Operator Error

MaintenanceError

Maintenance procedure[failure inform work

not completed]

Steam CleaningProcedure

PVCControl

(isolated)

Pressure reliefsystem

(isolated)

Watchmen system

(not implemented)

WK order / LOTO[Work not completed,left in dangerous state]

Failure follow workcontrol system

Inadequate pre-use inspection

Enhance permitsystem

Improper Servicingof Eqpt

Failure tocommunicate

Inadequateprocedure

EnhanceMaintenance proc

Failure to followprocedure

Make safety deviceinoperative

Enhance workpermit process

Improper operationof equipment

InadequateSupervision

Improve OperatingProcedure

Make safetydevice inoperative

Failure towarn

Inadequatecommunication

Enhance workpermit process

Enhance trainingsystem

AmmoniaPressure Vessel

Goodyear Tyre & Rubber

Company: overpressure

and burst

›› figure 2: example of bsCat build-out (from a public us Chemical safety board investigation report)


JOiNt iNDUstry PrOJects

The power of joining forces

every year DNV invites its staff to propose

new ideas for technology and service development. in 2012, we completed

200 development projects within the Cutting edge and technology leadership portfolios covering the maritime, oil & gas and cleaner

energy sectors. 29 were Joint industry Projects (JiPs), where we worked closely with industry partners.

the following pages present six of our current JiPs. we welcome your responses, and invite you to seek further information, or to join

us in our efforts to solve industry challenges.

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Subsea forgings JIP – a win–win for the industry

a major portion of a subsea project’s lead time is due to delivery times for large steel forgings used in making key components, such as X-mas trees. Due to company-

specific requirements, suppliers will not normally stock most such forgings prior to a project call-off, and the typical delivery time can be in excess of seven months.

TEXT: bjøRn søgåRd, DNV

A unified set of requirements across the industry is expected to make procurement easier and help to reduce quality prob-lems. On this basis, and in response to ini-tiatives from key stakeholders in the subsea community, DNV has taken steps to estab-lish a forging-material Joint Industry Pro-ject (JIP). This JIP – which aims to provide a Recommended Practice for global use – should be seen as a contribution towards a win-win situation for the industry.

baCkgRound/CHallenge The motivation for the JIP is to improve the quality and reduce the cost and deliv-ery times of forgings for the subsea indus-try. Due to quality concerns, end users of subsea systems typically have company-specific requirements for subsea forgings. This makes stocking prefabricated forg-ings, and thereby shorter lead times, diffi-cult for the vendor industry. A prerequisite for shortening lead times and making pro-ject execution more efficient is the timely availability of forgings that meet all likely end users’ quality requirements.

The material quality and confidence in a forging shop’s products are strongly influenced by knowledge of the plant and its resources, including company inspec-tors. Today, the subsea industry is facing increasing demands in terms of volume. Consequently, manufacturing sites are being established in new regions and sup-ply chains are becoming increasingly glob-al, generating new challenges with regard

to forging shops which may have limited or no experience with the applicable requirements in the subsea industry and locations that are more remote and less accessible for follow-up and surveillance.

ensuRing HigH QualitY The approach to ensure consistently high and repeatable quality across both the industry and geographical regions, and to build confidence in the final product, is to adopt a unified material standard with a consistent methodology to manage all the steps in the supply chain processes.

The project will incorporate valuable

contributions from, and the experiences of, major oil companies, subsea contrac-tors and manufacturers of steel forgings.

DNV will contribute its own pool of subject-matter experts who have wide expe-rience in this field.

Quality cost with increasing batch size

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BJørN søgårD

if you would like to know more or participate in the JiP, please contact DNV’s project manager, bjørn søgård,business Development leader well, subsea and [email protected]

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›› the JiP aims to improve the quality and reduce the cost and delivery times of forgings for the subsea industry.



Elevating the industry to a higher level

Jacking gears are by definition the most characteristic systems of self-elevating units or jack-ups. Despite this prominent position, they often remain

neglected on board, with a high potential for dire consequences.

TEXT: sVein inge leiRgulen, DNV

In order to achieve higher availability, reduce the risk of gear failure and lower the life cycle cost, DNV invites the industry to participate in a Joint Industry Project (JIP). The project’s main focus will be on defining best practices in the maintenance and inspection of jacking gears.

“The consequences of jacking gear fail-ure range from the operator being unable to reposition the platform to logistical challenges in correcting the failure. The worst case scenario is if the failure occurs in the middle of a jacking operation, as this may lead to an unstable platform that is prone to wave impacts. This implies a concrete danger to the unit,” says DNV’s Offshore Class product manager, Michiel van der Geest.

“Facing these risks, the need for

professional follow-up in the inspection and maintenance of jacking gears is obvi-ous, but not directly straightforward from a practical point of view. The high turno-ver of people with specific knowledge on board, the evolving nature of the systems and the natural focus on merely the pro-duction process and systems on board make this follow-up often challenging for an owner,” Michiel van der Geest explains.

Based on their respective backgrounds as a classification society and recognised service supplier, DNV and Dutch com-pany WillTeco have initiated a project to improve the inspection and maintenance of jacking gears. “In our experience, the best way of solving common industry chal-lenges is to join forces,” explains Michiel van der Geest, “so we decided to carry out

the initiative in a JIP and directly invite all the players in the self-elevating segment to participate. It’s only by including the experiences and relevant considerations of other industry players that the objectives of the individual partners can be reached,” he states.

The JIP’s goal is to develop a recom-mended practice document that describes the solution to achieve higher availability and at the same time reduces the risk of jacking gear failure. The overall life cycle cost will also be on the agenda. The JIP plans to collect and analyse experienced (near) incidents, mutually review current inspection and maintenance work support-ed by risk-based modelling and, finally, define and select best practices.

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Michiel vaN Der geest

if you would like to know more or participate in the JiP, please contact DNV’s project manager, michiel van der geest, Product manager, offshore [email protected]

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›› worst case scenario of jacking gear failure – an unstable platform prone to wave impacts and a high potential for dire consequences.



Determining a more accurate vortex-induced vibration (VIV) assessment of complex jumpers

treating increasingly complex jumpers as free spanning pipelines may no longer be the best approach. DNV is establishing a joint industry project to find out whether this is a problem

and, if so, to gather the knowledge necessary to better assess these risks and manage them more effectively.

TEXT: kRistian n. lindøe, DNV

It has been noted lately that the industry is increasingly considering complex jumper systems (such as U-shaped, M-shaped and Z-shaped jumper systems), whose structure may comprise pipe sections of various ori-entations. Even though complex jumper systems are advantageous with regard to their increased flexibility (end displace-ment tolerance), they also bring unique challenges of their own, such as in the VIV fatigue assessment.

There are limited studies on these com-plex jumper systems. The length of each structural member (legs), angle subtended by the legs (for 3D systems), current direction, shedding patterns, stress type, etc, influence the VIV of such complex jumper systems. These factors result in a system that deviates from the parameters set forth in DNV RP F105 (Free Spanning Pipelines) and may consequently lead to fatigue failure that is beyond the design predictions.

Currently no software (or validated methodology) exists for VIV assessment of complex structures. Strictly speaking, there is also no empirical data to validate any of the damage assessment calculations on non-straight geometries. This JIP is part of DNV’s on-going effort to bridge this gap.

›› Complex jumper systems are advantageous with regard to their increased flexibility, but they also bring unique challenges of their own, such as in the ViV fatigue assessment.

›› simple Pipe

›› u-shaped

›› m-shaped

›› Z-shaped

araviND Nair

if you would like to know more or participate in the JiP, please contact DNV’s project manager, aravind Nair, senior engineer. [email protected]

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The JIP aims to: ■■ Address gaps in the state-of-the-art assess-ment of complex jumper systems

■■ Estimate and improve the safety level in the current damage calculation approach

■■ Provide the industry participants with a first-of-a-kind design guideline docu-ment to address VIV assessment of the complex spools.



Vortex-induced motion study for deep draft

semisubmersiblesDeep draft semisubmersibles in the gulf of mexico are subject to high currents

associated with the loop current and eddies that can lead to large amplitude Vortex-induced motion (Vim). this can result in significant fatigue in moorings and risers. more knowledge is needed to manage this risk adequately, as current practices are overly conservative and costly. DNV is therefore establishing a Joint industry Project

to develop best practices for quantifying Vim for deep draft semisubmersibles.


Operators have stated that the existing design practice (tow tests) for VIM is inadequate and overly conservative for the design of mooring and riser systems. They wish to remove this conservatism by using a combination of full-scale measurements and Computational Fluid Dynamics (CFD) in order to fully represent parameters that cannot be included in tow tests, such as velocity shear, surface wave effects and velocity direction variation with depth. Removing present conservatism could reduce the cost of the mooring and riser systems for a deepwater field development project by around USD 10M. This would easily justify funding CFD work at an order of magnitude of USD 100K per project (i.e., 1% of the savings achieved in reduc-ing mooring and riser system costs).

This project will leverage existing model test results and field measurements as appropriate from information available in the public domain. In addition, VIM mitigation will be explored by performing hull geometry modifications or using VIM mitigating devices. CFD analysis will be used to understand semisubmersibles’ VIM and sensitivity to various parameters by studying the fluid flow and VIM response. CFD will also be used to evaluate and opti-mise the VIM mitigation strategies, such as

›› Current design practice for Vim is inadequate and overly conservative for the design of mooring and riser systems. more knowledge is needed to manage this risk adequately.

rOBert gOrDON

if you would like to know more or participate in the JiP, please contact DNV’s project manager, robert gordon,senior engineer. [email protected]

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strakes, and help screen the VIM mitiga-tion strategies to be model tested. Finally, VIM and VIM mitigation will be summa-rised in the form of VIM design guidelines.

In order to study the problem and develop a plan, background work will need to be performed. Systematic CFD will then be carried out to study and improve the VIM performance of the semisubmersible hulls. Overall, the study will yield a better understanding of semisubmersible VIM and provide options to mitigate VIM.

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Improved design, analysis and testing

of umbilicalsDNV is launching a Joint industry Project to gather knowledge to find out how increasingly complex

and valuable umbilicals perform over time.


Subsea umbilicals are now designed with multipurpose functionality such as subsea control and monitoring, chemical injec-tion, gas lift and electric power transmis-sion. In deepwater, dynamic umbilicals have to withstand high-end termination loads and fatigue issues. Calculating what can go wrong with these valuable and complex systems demands computing power and insight. To provide the industry with improved methods and analysis tools

for the safe and reliable design of subsea umbilicals, DNV invites operators and manufacturers to review umbilical test data for calibrating tools and validate analytical tools and methods.

Planning the umbilical qualification test programme is extremely important for understanding the complex cross-sectional behaviour of umbilicals. Proper instrumentation of the umbilical test speci-men is vital to establish the link between

physical tests and analytical methods. DNV will launch this Joint Industry Project (JIP) together with UltraDeep.

Key deliverables of the JIP include the development of a state-of-the-art guideline for testing umbilicals and a report on the design and analysis of umbilicals validated against test data. Findings will be directly applied to the HELICA and ABAQUS analysis tools.

MayUresh DhaigUDe

if you would like to know more or participate in the JiP, please contact DNV’s project manager, mayuresh Dhaigude, senior engineer. [email protected]

cONtact iNFOrMatiON

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›› in deepwater, dynamic umbilicals have to withstand high end termination loads and fatigue issues. what could possibly go wrong?



Stimulating investment in energy efficiency

measuresin close cooperation with ship owners and charterers, DNV has compiled tools

that ship owners and charterers can use to reduce fuel consumption.

TEXT: sYnne oPsand, DNV

The problem of split incentives is well known in the shipping industry. “It is an unusual situation for a business,” explains Knut Ljungberg, DNV’s project manager. “The ship owners control the initiatives, while the charterers benefit from reduced fuel expenses.” In a joint industry project called Energy Efficient Offshore Partners, seven offshore support vessel (OSV) own-ers and two charterers have been work-ing together with DNV to mitigate this barrier to investment in energy efficiency measures.

Phase I of the project was completed in September 2012. In this phase, several energy efficiency measures and their

reducing effect on fuel consumption were identified, including an improvement potential of 16%. The seven shipping companies together own and operate 170 vessels. With the vessels emitting around 1.7Mt of CO2 every year, the initiative will have a considerable impact on the environ-ment. Having the charterers involved cuts the charterers’ fuel costs and makes sure the initiatives spread to other vessels too.

In phase II, practice guidelines were established, as were a communication framework and an incentive scheme to split the financial reward gained from the reduction in fuel consumption. Examples of key focus areas included DP operation

and propeller polishing. A common plat-form with agreed initiatives will be much easier to communicate and implement in the industry.

The last phase of the project will be set in motion in June 2013. This is a pilot project in which the guidelines, commu-nication framework and incentive scheme will be applied together with the imple-mentation of energy efficiency measures on several ships over a period of four months. Successful results in the pilot may make way for a common practice in the industry.

KNUt lJUNgBerg

if you would like to know more or participate in the JiP, please contact DNV’s project manager, knut ljungberg,Principal [email protected]

cONtact iNFOrMatiON

›› fuel is a major cost item today and DNV can assist with all aspects of reducing fuel consumption from implementation of operational energy management services to technical solutions, such as retrofitting fuel saving devices on existing ships.

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OFFshOre class

DNV enhances offshore class rules

DNV has restructured its offshore classification rules for mobile offshore units in order to improve transparency and enhance safety. “our aim is to help the rig owner in the building process – to clearly

show that the unit is constructed in compliance with reliability and safety standards. at the same time, yards can achieve improved control of the building process and have the ability to document the safety level of alternative solutions,” says erik henriksen, Director for mobile offshore units at DNV.


International offshore regulations and requirements are constantly adapting to new conditions, technologies and safety issues. Class rules prescribe how the regu-lations are to be met and help the owner and yard in designing and constructing the newbuild. But achieving an optimal result requires a delicate balance between detailed prescriptive vs. functional and more general requirements. The first ensure predictable and transparent results, while the latter allow the application of alternative solutions.

added Value “As a class society, DNV aims to provide clear and updated rules to ensure that off-shore units are safe, efficient and reliable. This is where DNV gives added value, since a more reliable unit equals less downtime,” says Henriksen.

DNV is continuously developing its standards and guidelines in order to be in the forefront. “We have launched an enhanced and restructured version of our offshore classification rules for Mobile Offshore Units. I’m confident that these will provide stakeholders with a clear description of the technical requirements. As before, the rules are aligned with the IMO MODU Code, International Asso-ciation of Classification Societies (IACS) Unified Requirements and other relevant

international standards and codes. How-ever, in addition, they include a compre-hensive description of interpretations. This makes the rules’ requirements easy to understand and apply throughout the design, construction and operation of the asset,” he points out.

going beYond basiC ReQuiReMents DNV recognises the competitive advantage of building in excess of the basic level required for compliance with regulations. Going beyond basic requirements will not only result in improved safety, but also increase reliability and hence have a direct

positive effect on downtime. For owners looking to achieve this advantage, DNV has added an extra level of system require-ments defining the optional Enhanced Safety class notation.

Specifically, the restructured rules pro-vide advantages to all parts of the value chain.■■ EFFICIENCY; they enable more efficient production that meets internationally accepted standards without being lim-ited to prescriptive solutions

■■ RELIABILITY; they provide assurance that the unit meets reliability and safety standards without the burden of unnec-essary disputes

■■ TRANSPARENCY; they create trust that safety and design principles are implemented by following detailed interpretations

The enhanced and restructured format is now open for comments during a six-week consultation period. Subsequently, DNV will update the standards based on the input received, followed by final publication.

›› erik henriksen, Director for mobile offshore units at DNV

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Visit www.dnv.com/offshoreclass to learn more, download the rules and provide comments.


OFFshOre class

MAIN CLASS

BEFORE NOWUniform with a renowned quality but less transparent.

VOLUNTARY NOTATION ES

Aligned with the internationalaccepted safety standards.

FUNCTIONAL MAIN CLASS

Improved safety and reliabilityin a cost efficient manner.

A NEW DIMENSIONInterpretations ensuring control on the newbuild process and deliveries.

MAIN CLASS

ENHANCED SYSTEMS

›› going beyond basic class requirements.

›› DNV aims to provide clear and updated rules to ensure that offshore units are safe, efficient and reliable. this is where DNV gives added value, since a more reliable unit equals less downtime.

aBOUt DNv OFFshOre classiFicatiON services

stakeholders such as financial institutions, shareholders, insurers and society at large have a similar focus on the safety and reliability of mobile offshore units (mous). accidents are not tolerated in modern society. DNV helps customers to ensure adequate safety and reliability through offshore classification during all phases of the asset’s lifetime, i.e. design, construction and operation.

DNV establishes basic rule requirements based on theory and its experience of mous, and later verifies that the required safety standards are incorporated into the design and that the safety level continues to be maintained throughout the unit’s life cycle.

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OFFshOre class

Free choice of class for floaters in the Gulf of

Mexico – DNV is chosenClassification and CVa (Certified Verification agent) contract with DNV for

Delta house floater marks a new era of choice in the gulf of mexico.


DNV has been awarded the classification contract for a new build floating produc-tion semi-submersible platform for the GoM. The Delta House floater will be operated by LLOG Exploration Company, a premier private exploration and produc-tion company in the Gulf of Mexico.

Following a detailed review of DNV rules and procedures, the U.S. Coast Guard has confirmed it will accept plan review and inspection functions conducted by DNV for the Delta House floater as part of the unit’s certification under Title 33, Code of Federal Regulations. This follows from the general acceptance given by the U.S. Coast Guard in 2007 and provides a new option for owners and operators of offshore floating units.

“Owners have expressed a strong desire to choose the classification society for floating offshore installations in Ameri-can waters and we know there are many owners, designers, operators and yards that would prefer to work with DNV. This contract is proof that they can do so and be confident of legal and regulatory approval,” said Kenneth Vareide, DNV’s Director of Operations for Maritime in North America.

“With its local capabilities and exper-tise, DNV is a well-established alternative and experienced partner for classing float-ers and complex projects in the Gulf of Mexico. We now look forward to address-ing the industry’s needs and desires for increased safety, reliability, cutting-edge

technology and, of course, reduced down-time. We are confident that both owners and regulatory agencies will benefit from this,” he said.

DNV has carried out extensive verifica-tion and independent analysis work on many GoM floaters throughout the past 20 years, including many high profile failure and accident investigations. The company has a wide portfolio of CVA and develop-ment projects for the oil and gas industry in the GoM. DNV was also the classifica-tion society and CVA for the first FPSO on the Cascade and Chinook field in the US GoM.

DNV will carry out approvals of classi-fication and verification work and surveys related to activities in the US. The Bureau

of Safety and Environmental Enforcement (BSEE) has also appointed DNV as the CVA for the structure, mooring and riser, and all this work will be executed from the Houston office. The Design Basis Agree-ment for Delta House, as approved by the Coast Guard, is largely based on DNV’s offshore rules for a FOI (Floating Offshore Installation).

The hull is designed on the basis of EXMAR Offshore Company’s proprietary OPTI-11000® and will be fabricated in Korea, at Hyundai Heavy Industries. The topside production system is designed by New Orleans-based Audubon Engineering Company, and fabrication and integration with the hull will take place at the Kiewit Offshore Services Yard in Ingleside, Texas. The completed FOI will be installed on the Mississippi Canyon block 254 in the deep-water U.S. Gulf of Mexico. Fabrication of the hull starts in early 2013 for planned production in 2015.

DNV is currently also classifying eight newbuilding projects as well as OSVs, div-ing support vessels and a U.S. flag ro-ro/container ship for the U.S. Jones Act trade. These are at various stages of construction in U.S. yards in the Gulf and on the East Coast.

Globally, DNV’s market shares of clas-sification contracts awarded for newbuild-ings in 2012 were as follows: FPSO/FSRU 70%; drillships 30%; semi-submersibles 60%.

›› the Design basis agreement for the Delta house floater is largely based on DNV’s offshore rules for a floating offshore installation.

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New class notation for seismic vessels

DNV has developed a new class notation for seismic vessels in consultation with key industry players such as westerngeco, Pgs and fugro-geoteam. the need to have

enhanced redundancy and proper deck arrangements to ensure continuous operations without any loss of speed is the backbone of these new technical requirements.

TEXT: PeR wiggo RiCHaRdsen, DNV

Seismic vessels contain high-end comput-erised technology to find resources below the seabed, and represent a key element in the value chain leading to future offshore field developments. Any interruptions in the ship’s forward movement can compli-cate the seismic data processing, so contin-uous operations with a focus on avoiding any downtime of key functions are of the utmost importance. With expensive seismic streamer equipment mobilised at sea, any sudden loss of service speed may lead to severe consequences, such as damage to cables that impairs the whole seismic vessel operation.

The new notation focuses on the increased availability of the vessels during critical phases of the seismic operations. As well as vessel operators, DNV has consulted seismic handling and high-pressure equip-ment suppliers to ensure that all current and future industry challenges are compre-hensively dealt with.

The new notation was released last year and strengthens DNV’s position in the seismic classification market as the indus-try focuses more strongly on deepwater, frontier exploration. “DNV has the great-est share of this market. More than every second seismic vessel is DNV-classed. By introducing the new class notation, we are helping owners in this high-tech special-vessel segment to meet future demands with the utmost safety and reliability,” says Jan Kvålsvold, Director for Market and Business Development.

Maintaining propulsive power is a key issue. The class notation has therefore taken the DNV concept for redundant pro-pulsion one step further so that any failure on board will not lead to the loss of more than 50 per cent of the forward thrust. This is sufficient to maintain a minimum speed of a few knots and will protect any high-cost air guns and streamers that are deployed.

Seismic vessels typically operate for many months continuously without seek-ing harbour. The class notation requires a deck arrangement that facilitates side-by-side transfers of crew and supplies from a seismic support vessel.

Beyond this, the class notation also sets a requirement for the bridge arrangement to ensure a good view of the streamers and any workboats that are close by during normal operations. High-pressure systems are also addressed in the class notation to ensure that deck operations can be carried out safely by the crew.

“The world’s energy demand is increas-ing,” said Mr Kvålsvold. “Even though new energy sources are being developed, fossil fuel will maintain its dominance well into the future. The demand for suitable seis-mic exploration vessels is already high and will continue to grow.”

›› Jan kvålsvold, Director for market and business Development

›› big, bold and beautiful – Pgs’ ramform titan – an icon for efficient marine 3D seismic acquisition

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techNOlOgy leaDershiP

Well capping technology at your service

in the wake of the macondo incident in the gulf of mexico, nine oil majors and oil spill response ltd (osrl) have developed new well capping stack

technology. the goal is to improve the response capability for subsea well incidents and the first capping stack is now installed in Norway.


For the first time on this scale, nine major oil and gas companies are working togeth-er with a leading oil spill response player – OSRL – to enhance international subsea well incident intervention capabilities. The Subsea Well Intervention Service (SWIS) includes well capping and dispersant equipment for international deployment if a subsea well control incident occurs. OSRL will store and maintain the equip-ment ready for mobilisation near air- and seaports in South Africa, Singapore, Brazil and Norway, for rapid onward transpor-tation to the incident site by the well operator.

The stacks can be used in a water depth of up to 3,000 metres and control flow pressures of up to 15,000 psi. The first sys-tem is now available for use by the industry from the Stavanger base, which was inau-gurated by Norway’s Petroleum & Energy Minister Ola Borten Moe in March.

The system builds on established indus-try experience and has been designed according to research into potential inci-dent scenarios and geographic variations in weather, ocean and oil conditions. It includes four capping stack toolboxes and two hardware kits for the subsea applica-tion of dispersant at a wellhead. The stor-age locations have been chosen due to international coverage, strong transport links and effective logistics for securing maximum readiness and swift mobilisation. The intervention system is designed to handle most subsea oil well incident sce-narios around the world.

dnV Qualifies tHe new teCHnologY DNV has been engaged by SWRP to undertake design verification, fabrication surveys and witness testing of the capping stack system. The project has also included elements from DNV’s Qualification Pro-cedures for New Technology. The main fabrication and testing activities have been carried out in Houston, but have also included fabrication surveys at different suppliers in Europe.

›› the first capping stack is available for use from the stavanger base. other systems will be available in south africa, singapore and brazil.

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NiNe MaJOrs iN ONe teaM

the subsea well response Project (swrP) is a joint project from nine operators; bg group, bP, Chevron, ConocoPhillips, exxonmobil, Petrobras, shell, statoil and total. their plan is to build four well capping stacks which will be placed at different strategic locations in the world. these are intended to be used as contingency if an offshore well blowout occurs and if the rig’s boP has failed. this capping stack system provides capacity to shut in the well stream or to divert the flow into a subsea containment system so the hydrocarbons can be collected.



A new revision of DNV’s offshore standard for Integrated

Software Dependent Systemsa new and more user-friendly version of DNV’s offshore standard for integrated

software Dependent systems (isDs) has been issued. DNV is experiencing increasing demand from the drilling market for this kind of service and has now established

a separate dedicated section in order to better serve this growing market.

TEXT: eVa HalVoRsen, DNV

Based on continuous dialogue with own-ers, yards and suppliers, DNV’s offshore standard OS-D203 has been revised in order to clarify the requirements for assigning an ISDS class notation to an offshore unit as proof of compliance with the standard as well as to clarify the text in general and remove known inconsisten-cies. In addition, the standard has become more user-friendly.

The following are the main improve-ments in the revision: ■■ It has established scope and confidence levels for selected drilling and well-inter-vention-unit systems in the standard;

■■ The information and defined expecta-tions related to roles and responsibilities for each involved party in an ISDS pro-cess have been structured and clarified;

■■ The standard text has been restruc-tured to make information more easily available;

■■ Security requirements have been introduced.

“The revision means that yards, owners and suppliers may now more easily deter-mine the scope and efforts related to implementing ISDS,” says Knut Ording, manager of the newly established Systems and software reliability section. “Besides, the standard is now more user-friendly and it’s easier to find information,” he says. DNV realises that addressing the safety and

reliability of integrated software depend-ent systems is now becoming an industry standard for offshore drilling units. That is why it has geared up to deliver high quality ISDS services to this industry in key loca-tions such as Norway and Korea.

eaRlY MoVeR DNV was the first classification society to set the safety and reliability of inte-grated software dependent systems on the agenda. The basis for the Enhanced Sys-tem Verification (ESV) class notation was launched in 2005 and ISDS was introduced in 2009. The demand for these services is growing rapidly.

“It’s also important to underline that all DNV’s technology development takes place in close cooperation with our customers and end-users,” says Knut Ording.

›› knut ording, manager of DNV’s newly established systems and software reliability section.

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HHI changes approach to systems and software on semi-sub newbuilding

hyundai heavy industries and Dolphin Drilling are implementing DNV’s isDs class notation for integrated software dependent systems on the semi-sub newbuilding drilling rig bollsta Dolphin. key stakeholders discuss expectations and challenges.

TEXT: wendY lauRsen

Mr Seong Cho, project manager at Hyun-dai Heavy Industries (HHI), admits reti-cence about taking on DNV’s ISDS stand-ard for complex systems in the building of Dolphin Drillings new semi-sub, Bollsta Dolphin. “At the beginning, some of us were not very positive about this program because we had lots of new activities to perform and many documents needed to be prepared,” he says. “But as our under-standing grows and the more activities are progressed, the more we feel positive about ISDS.”

MiniMising eRRoRs and delaYsThe ISDS notation establishes a methodol-ogy that aims to minimise software inte-gration errors and delays in projects that involve integrating software dependent systems. The notation includes the devel-opment of quality assurance processes that will last throughout the semi-sub’s opera-tional lifetime.

Hyundai Heavy Industries is the world’s largest yard and DNV is providing the full ISDS package including integration consulting. Mr Cho is positive about the potential benefits. “We expect a clearer interface between systems and fewer prob-lems during commissioning.”

All the parties, owner, yard, suppliers and DNV, will have to work very closely as a team for successful implementa-tion, he says. He believes change will be progressive.

ReVised standaRd“We are aware that the current edition of the Offshore Standard for ISDS has been a bit academic and not very well structured,” says Knut Ording, the Head of Section for Systems and Software Reliability in DNV and responsible for DNV’s ISDS classifica-tion services. “In order to improve this, the OS-D203 has been revised this year based on inputs from owners, yards and sup-pliers, with the aim of offering a clearer scope and improved ease of use. The revised standard was launched December 2012,” Ording continues.

stRuCtuRed CollaboRationSo far, Mr Cho has found DNV to be very supportive and Einar Tyssen, technical director for Fred. Olsen Energy, Dolphin Drillings mother-company, agrees. “They appear very proactive and dedicated to make the project a success,” says Mr Tys-sen. “Being involved in various other projects without ISDS, I have been very positive from the offset. Even though the project is in the early phases our main goal was to define a scope for the project so that the constraints could be defined and we could establish clearer interfaces between each system.

This will be the second project that Dol-phin Drilling has had with HHI. “ISDS for the Bollsta Dolphin has provided so far, a very good relationship between all parties, Dolphin, HHI and DNV. HHI is commit-ted in learning and developing ISDS into a quality assurance (QA) and integration-tool for the systems that they are providing for the Bollsta Dolphin.”

By combining the QA efforts towards all key vendors and by doing extensive hard-ware in the loop testing upfront of factory acceptance tests, Tyssen aims to reduce the need for rectifications during commission-ing and testing significantly. “We expect the critical systems to be operational sys-tems from day one after delivery and to have a reduced risk for hidden failures and thereby a reduced risk for failures on

›› einar tyssen, technical Director, fred.olsen energy

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safety critical systems while in operation,” he says.

Tyssen wants to treat changes in the software system in the same structured manner as they handle changes on other critical components on the rig. “For me ISDS is about planning things right and facilitating structured collaboration between all the key vendors including the yard to ensure that when all the sys-tems are installed its just plug and play. Our experience from the pilot we ran on Borgland Dolphin is that we significantly reduced the commissioning time after installation on board.”

DNV applies methodologies that have proven effective in the aerospace, telecom-munications, defence and automotive industries. Their experience with ISDS

from previous projects with Seadrill, Odfjell, Total and Statoil indicates that applying the ISDS class notation can eas-ily save USD 6-20 million by addressing potential problems early in a project and thereby avoiding the delays caused by the need to re-work software.

isds suCCess stoRies gRowAs DNV’s experience grows, so do exam-ples of ISDS success, says David Card, sen-ior principal specialist, Ships and Offshore Electrical at DNV. “Most suppliers have no structured way of making sure all software functionality has been verified,” says Card. This is corrected with the creation of veri-fication strategies and traceability from requirements to verification procedures.

“In an earlier project we found that the

yard had assumed the supplier was writ-ing the functional design specifications for the mud system. The supplier assumed the yard was writing it. ISDS assessments identified that it was not being handled.” In another case, interface design activities required by ISDS detected that the inter-faces for the rig data recorder were not being handled during design. Additionally, it was determined that some suppliers were proposing software solutions based on the Windows XP, no longer supported by Microsoft.

DNV hopes that the Bollsta Dolphin project will be a game-changer for the industry on how to design, build, install and test software systems.

›› the bollsta Dolphin project – a game-changer for the industry in how to design, build, install and test software systems.

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shale gas

Shale gas risk management: the importance of being trusted

the unconventional resource boom is in full swing, but public concerns about the environmental impact of developing these resources have mired the industry in controversy. to contribute to a solution, DNV has issued a

recommended practice (rP) for the entire lifecycle of shale gas extraction based on risk management principles and industry best practices and standards.

TEXT: CatHRine toRP, DNV

The RP is intended to form the basis for the future development of a worldwide recognised standard for safe and sustain-able shale gas extraction. The RP has been presented in London, Houston and, most recently, Beijing.

According to Steinar Thon, DNV’s associate director who was in charge of the development of the RP, DNV’s creation of the recommended practice grew out of the company’s core purpose: to safeguard life, property and the environment. “We could see there were certain guidelines and design standards for individual aspects of shale gas,” he says. “What we set out to do was to develop a more complete document to cover a wide range of risk categories. We also ensured that this recommended practice was in line with DNV’s experience with the oil and gas value chain. This fits well with our vision to have a global impact for a safe and sustainable future.

“Controversy and polarised debate are constant themes as proponents and opponents discuss the extraction of uncon-ventional resources,” says Thon. “Since the RP combines current best practices and standards in the industry with a risk-based approach, it can serve as a common reference point and help bridge the gap between parties with opposing views. Our recommended practice ensures that con-tentious issues are managed in an accu-rate, balanced, transparent and traceable way.”

HigH leVel of inteRest“The market has shown much initial inter-est in our approach,” says Lars Sørum, Director of Technology and Services for DNV Europe and North Africa. “We are continuously receiving requests to speak at conferences and present papers and are now established as the leading voice for risk management on the subject in Europe. We are also getting good response in North America. DNV will be presenting its views, services and the RP throughout the year at various conferences and to dif-ferent regulators around the world.”

The launch of the final version of the RP in Houston in January 2013 was met with keen interest in the mature US shale

gas industry. In China, too, both custom-ers and media are gathering to learn more about DNV’s risk-based approach to man-aging the extraction of unconventional resources. At the inaugural meeting of the IEA Unconventional Gas Forum, DNV was invited, as one of four industry players, to present how the RP compares to the IEA’s Golden Rules.

Sørum hopes to spark a debate about risk management between all stakeholders. “Obviously, the element of communication is very important,” he says. “Currently, the debate is very polarised both in academia and between the industry and other stake-holders. Having rational conversations and discussions based on facts is one of the best risk management methods out there.”

CollaboRatiVe deVeloPMent aPPRoaCHThon believes some of the success is due to the way in which the recommended practice has been developed. The frame-work was developed over an 18-month period, which included collaboration with stakeholders as well as a review of existing practices and guidelines. Multiple organi-sations have already developed recommen-dations and guidelines, but no complete risk management framework has existed. Although the practices are risk-based, they are technology-neutral, allowing for local differences, and are complementary to existing regulations.

›› steinar thon, associate Director, DNV

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shale gas

›› lars sørum, Director of technology and services for DNV europe and North africa.

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shale gas

Risk-based – not PResCRiPtiVe Thon says that many regulators aim to prescribe in detail how to ensure environ-mentally friendly and safe unconventional resource extraction, but he believes that focusing on the key risk elements is a more effective and yet safe way forward. “We have in various chapters addressed different risk categories and elements, and we’ve offered a series of risk-mitiga-tion strategies that can be applied,” he explains. “What we do not do is set up some kind of risk assessment, ranking risks against each other. This has, of course, to be determined from site to site and project to project.”

tRansPaRenCY Openness and transparency is another issue DNV strongly believes will contribute to positive developments. Unconventional resource operations must be monitored and publicly reported. Another impor-tant factor is to establish independently verifiable baselines, thus establishing proper points of reference and consist-ent monitoring prior to, during and after operations. These baseline surveys must be openly disclosed to all stakeholders, including the general public.

In addition to robust governance to ensure risk management, the independent verification of critical operations, equip-ment and processes is an important tool for the industry. “We believe that com-panies that embrace our approach and recommended practice will earn increased

trust and confidence among the general public and other stakeholders. Companies can build confidence by implementing internationally recognised operational best practices and industry standards to document that their activities are being executed in a safe and responsible man-ner, ” Sørum emphasises.

He adds that: “This recommended practice is not meant to replace what is already there in terms of regulations and standards, but rather to complement them. Throughout the chapters, we make reference to several others standards and guidelines.”

soCial liCenCe to oPeRate “In Europe, the governments of different countries with unconventional resources require companies that want to embark on exploring for these to demonstrate to the authorities that they have robust enough capabilities and competence to

succeed. In some countries, before a com-pany even starts to work in the country, it has to demonstrate to regulators that it has identified all the risks and has the governance needed to handle the risks. By applying the process of independent verifi-cation and demonstrating compliance with recommended practices, an operator can build trust among regulators too,” Sørum explains. DNV’s role as an independ-ent third party provides a level of trust between operators and the public. The recommended practice encourages opera-tors to be transparent.

“We hope to see a positive response from the public,” he added. “We want to be able to assist the industry and alleviate some of the public’s concerns. There’s a fundamental lack of trust between the public and operators. As an independent third party that has developed a set of rec-ommended practices, we have the basis for verifying that the operators are doing what they say they’re doing.”

Potential unConVentional ResouRCe ReVolution in CHinaEurope seems to be following on the back of the relative maturity of unconventional resource developments in North America, but may develop more slowly due to its complex regulatory and social structures. So will the next revolution be in China? With recoverable resources of up to 36.1 trillion cubic metres, China has the world’s largest deposits of shale gas and has set ambitious targets for shale gas exploita-tion. In its 12th Five-Year Plan, China states it aims to produce as much as 6.5 billion cubic metres of shale gas a year by 2015, which would be equivalent to 3 per cent of China’s total gas production in 2015. By 2020, China intends to produce up to 100 billion cubic metres of shale gas. “China’s shale gas ambitions match our introduction of the RP. We believe the RP as such will contribute to the regulation of, and framework set-up for, the sustain-able development of China’s shale gas industry,” says Stone Zhang, DNV’s Direc-tor of Operations for Oil & Gas in Greater China.

›› abundant shale and tight gas, and oil resources have begun to transform the global energy outlook.

“Currently, the debate is very polarised both in academia and between the industry and other stakeholders. having rational conversations and discussions based on facts is one of the best risk management methods out there.”

lars sørum, Director of technology and services for DNV europe and North africa

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FlNg

FLNG – an old idea comes of agein its 2011 world energy outlook, the iea asked the question “are we entering

a golden age of gas?” Nothing, of course, can ever be certain but there are very many signs pointing to a positive answer to that question.

TEXT: Conn fagan, DNV

The current and projected future availabil-ity of natural gas, from both conventional and unconventional sources, the widening demand and increasing range of applica-tions, the focus on the need for supply security and diversification, and the rela-tive environmental benefit compared to other fossil fuels all point in the direction of a bright future for natural gas.

As a means of bringing this gas to market, transport as LNG is a flexible solution and in many cases the only techni-cally feasible solution in competition with pipeline transport. For offshore gas wells, the option of producing this LNG at the offshore location rather than first piping it to shore for LNG production has now become a viable solution in terms of both the availability of technology and project economics. In that development, DNV has and has had a key role to play.

tHe HistoRY DNV has had a long involvement in the LNG industry, indeed from its very start. We have, of course, played a central role in the marine transportation of LNG, class-ing a large number of the gas carriers cur-rently in operation and having had a key role in the initial development of the main technologies for LNG containment. How-ever, our engagement in floating liquefied natural gas (FLNG) units also stretches back in time to some of the earliest

assessments of FLNG concepts. For exam-ple, an FLNG unit was originally proposed for the Kangan field in Iran and DNV car-ried out a design assessment of the Kværn-er/Moss barge-mounted liquefaction plant design. This resulted in the development of the first rules and recommendations for FLNG units in 1979.

We have naturally followed the develop-ment of FLNG concepts since then, from concrete barge structures to the current designs using ship-shaped structures which parallel the development of oil FPSOs. Our long involvement with the marine LNG industry, including with many of the fleet of LNG floating storage regasification

units (FSRUs) currently in operation, and our work on the most complex FPSOs in some of the most challenging locations, together with the verification and con-sultancy work which we have performed for many years for the land-based LNG industry, enable us to continue to play an important role in developments in floating LNG applications.

tHe CuRRent suRge In the last 10 years, we have seen FLNG concepts and technologies maturing so that today the first construction projects are under way. These reflect the confi-dence of investors, operators and regula-tors that the work of the past 30 years has resulted in a technology capable of being deployed and considered as a viable field development option.

At the time of writing, there are two FLNG units under construction for opera-tion in the Asia-Pacific region, one of which is being built to DNV class. While much of the focus today is on this geo-graphical area, with a significant number of FLNG units being proposed to tackle the planned development of Australian gas fields, such units are currently being proposed as the solution for gas fields in very many geographical locations, includ-ing both North and South America, East and West Africa and the Eastern Mediterranean.

›› Conn fagan, Vice President, DNV maritime and oil & gas.

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FlNg

›› we foresee that flNg units will move into similar areas as oil fPsos and perhaps into areas where gas development may be more acceptable than oil development, such as the arctic region.

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DNv’s OFFshOre techNical gUiDaNce FOr FlOatiNg liqUeFieD gas terMiNals

this publication compiles the essence of more than 30 years of DNV research into one document. it presents a guideline for the design and classification of floating installations for handling liquefied natural gas.

the guideline describes principles and procedures and provides guidance on classification requirements. it further addresses a number of technical issues considered to be especially relevant for floating lNg installations. this document is intended for guidance only and should be used together with the relevant DNV rules, DNV oss 103 Rules for the Classification of Floating LNG/LPG Production, Storage and Loading Units and the associated DNV offshore standards which specifically address the relevant engineering disciplines. for classification purposes, the requirements given in the DNV rules are to be used. a prime objective is to address the risks specific to floating liquefied gas concepts and how they can be managed by applying offshore classification systematics.

Many of the presently planned projects are entering the pre-FEED or FEED phases and DNV has been involved in helping designers and project owners to ensure a safe and effective design. These projects involve concepts with variations in vessel size, production capacity, gas composition and key technologies, such as liquefaction-plant, containment and LNG-transfer systems. To address these developments, DNV has developed specific Rules and Guidelines for such concepts which bring together DNV’s long experience within the area.

tHe futuRe If the outlook for gas and LNG continues as anticipated, we foresee that FLNG units will move into similar areas as oil FPSOs and perhaps also into areas where gas development may be more acceptable than oil development, such as the Arctic region. The development of current technology relating to transfers, containment and processing will permit the concept to move

from benign environmental areas of the world to more challenging areas. Develop-ment is likely to involve both ultra large scale production capacities on large float-ing units and much smaller scaled units capable of economically exploiting smaller reserves. The range will stretch from using some of the most complex floating units ever built to much simpler units, perhaps involving barges in combination with a storage vessel. It is anticipated that floating units may also serve to process gas from land wells, including both shale gas and coal seam gas, given the possibility of build-ing such units at a reasonable cost and within a reasonable time frame compared to a land-based development.

With its wide range of services and long and ongoing history within the FLNG industry, DNV aims to continue developing its technology and business knowledge in order to serve its clients within this exciting business area.

Download the publication

more valuable information covering the entire lNg value chain available from blogs.dnv.com/lng

››


FlNg

›› Producing 1.2 million tonnes a year (mtpa) of lNg, PflNg 1 is expected to be the world’s first floating liquefaction unit in operation when completed by the end of 2015.

DNV to class PETRONAS FLNG Unit, expected to be

the world’s first in operationDNV has been awarded the contract to class PetroNas’ first floating lNg unit

(PflNg 1), destined for the kanowit field offshore sarawak, malaysia.

TEXT: PeR wiggo RiCHaRdsen, DNV

The unit will be 360m long and 60m wide and is to be moored 180km from shore. It will produce 1.2 million tonnes a year (mtpa) of LNG, and is expected to be the world’s first floating liquefaction unit in operation when completed by the end of 2015.

The scope of DNV’s contract includes the floating structure, mooring arrange-ment and natural gas liquefaction technology.

The floating LNG unit negates the need for a costly or technically problematic off-shore pipeline to transport the gas back to a land-based liquefaction plant and includes liquefaction technology designed for use on a floating facility.

“The ability to process and offload LNG offshore will increase the viability of significant gas reserves in remote and stranded fields and, beyond that, we fore-see a number of these very high invest-ment projects being built throughout the world as a means of developing gas fields and transporting the gas economically to market,” says Conn Fagan, Vice President of Floating Gas Project Business Develop-ment at DNV.

“There is currently a high demand for LNG,” says Mr Fagan. “It can be a cost-effective solution for supplying the energy needs of rapidly growing cit-ies such as those in Bangladesh, China, India, Indonesia and Vietnam, as well as

providing flexibility of supply for consum-ers currently reliant on pipeline gas. This demand, coupled with the presence of large offshore gas reserves, some in remote locations, has made the floating LNG pro-duction unit an interesting technical and economic option. DNV is at the forefront of FLNG technology and we are building

competence around the world to support PETRONAS in this project and other customers who are entering the field. This is cutting-edge technology for the oil and gas industry and will have a dramatic impact on the nature of upstream business around the world.”

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arctic OPeratiONs

Can Arctic risk be managed?

exploration for natural resources in the arctic carries a set of additional risk factors. “it is a challenging act to balance, but i think arctic risks can be managed provided some principles are followed. Collaboration and development in a stepwise manner are key elements,” says knut Ørbeck-Nilssen, Coo

of DNV’s operations in Norway, finland and russia.


“I agree that it is a paradox that the melt-ing ice cap opens up for more hydro-carbon extraction, but global warming requires global solutions. And it is a fact that the need for rare minerals, oil and gas will drive the need for activities further north the coming decades. Another impor-tant driver is that the Arctic is actually a politically stable area. This strengthens its relative position regarding safe and pre-dictable access to resources and transport routes in particular through the North East passage,” explains Ørbeck-Nilssen.

“Most people don’t realise that much of the legal framework is in place as most of the undiscovered oil and gas is within national jurisdictions determined by UN Resolutions, for example. Concerns about a ‘race’ to exploit these resources are somewhat misguided – so what we are talk-ing about is harmonisation. Also, the polar code issued by the International Maritime Organisation will be critical to regulate positively shipping and maritime activity,” he says.

diVeRsitY Calls foR a stePwise aPPRoaCH “Many speak about the Arctic as one place, but it is not one homogeneous area with the same set of opportunities and chal-lenges everywhere. Actually, it is a very diverse part of the world,” Ørbeck-Nilssen highlights.

Some areas, such as the southern part of the Barents Sea, can be considered very similar to the North Sea with respect to cli-mate conditions. But, in contrast, the east coast of Greenland is a far more remote and difficult area for offshore operations.

“Generally, its remoteness and harsh environment make the Arctic a challeng-ing place for possible rescue operations and oil spill response operations, for instance. Since there is not one Arctic, but many Arctics the challenges faced in one area may not be an issue in others. And, practically speaking, technologies and pro-cedures suitable to one area may not be fit for purpose in others,” Ørbeck-Nilssen emphasises.

Therefore, in order to ensure safe opera-tions in the Arctic, the industry will benefit from starting exploration in areas whose conditions are not so different from those we are used to today. Hence, we should not move to the more unexplored areas before improved technology has been developed and sound experience has been gained in the ‘easier’ areas. This is what we refer to as a stepwise approach,” he says.

Manage tHe Risks – not onlY ConseQuenCes According to Ørbeck-Nilssen each Arctic region has its individual set of risks and these have to be managed. “But even though risk is the combination of ‘Prob-ability’ and ‘Consequence’ many tend to focus on the consequence only and neglect the associated probability of an accident happening. In order to have a complete risk overview, both the probabili-ty and consequence need to be thoroughly identified and analysed. And I would like to point out that all industrial activity


arctic OPeratiONs

›› knut Ørbeck-Nilssen, Coo of DNV’s operations in Norway, finland and russia

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arctic OPeratiONs

involves risk. The risk can never be zero unless an activity is prohibited, meaning zero activity.”

soCietY Must agRee on an aCCePtable Risk leVel Acknowledging that there will be Arctic activity, Ørbeck-Nilssen recommends that a risk-based approach is the most appropri-ate one, since both possible probabilities and possible consequences are to be con-sidered in a transparent manner. In this way, the risks and benefits of activities are also balanced.

“However, the society must determine the optimum balance between the risk and the associated benefits of activity in the Arctic. Willingness to accept risk also means that society can harvest the ben-efits,” he explains.

But a very relevant question is – what is acceptable risk? That means how much risk is society willing to take in order to harvest such benefits and, in even more practical terms: How safe is safe enough?

Ørbeck-Nilssen says that to answer

this, a thorough discussion between the industry, regulatory bodies, authorities and especially the society at large needs to be done. Most probably the views will differ, but transparency and openness will foster understanding and mutual respect for the different viewpoints.

safe as tHe noRtH sea? The oil and gas industry has learned a lot from its operations during the past few years. Not least major offshore accidents have led to great improvements in regula-tions and technologies so that risk can be better managed. For instance, the occupa-tional risk on the Norwegian Continental Shelf has improved significantly.

“For DNV, it is an important principle that the risk level in the Arctic must be equivalent to – or better than – the best performance in the industry today. In this context it might be fair to say that the North Sea is one of the safest continental shelves with respect to oil & gas activities. Accident statistics indicate this to be true,” Ørbeck-Nilssen says.

The consequences of an accident in the Arctic are likely to be more severe than in other areas. “So achieving a risk level in the Arctic that is equivalent to the level in the North Sea will require a special focus on reducing the probability of incidents. However, accidents may occur and we should not forget appropriate prepared-ness to mitigate their consequences,” he points out.

Appropriate preparedness capability is in some cases challenging. For instance, in response to oil spills in ice, the best option today is dispersants and burning while there is no mechanical recovery option. Ørbeck-Nilssen explains that to address some of the capacity challenges relating to oil spill preparedness, DNV has for instance looked into using the fishing fleet with the innovative Catchy fishing vessel concept. Here the gear is adaptable to a wide range of other uses, such as remotely operated vehicle operations and oil spill recovery.”

Safety barriers=

Managing threats to prevent

an accident

Mitigating the consequences of

an accident

›› managing safety barriers: risk management means identifying, assessing, prioritising, minimising and mitigating risks. (Complex systems fail in complex ways).

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›› given that further exploration in the arctic will take place, DNV believes that the industry can develop ways to safely explore the arctic region provided some guiding principles are followed.

arctic OPeratiONs

deal witH baRRieRs ‘Complex systems fail in complex ways’ is a clear conclusion after the 2010 Macondo disaster in the Gulf of Mexico. Here, many barriers didn’t work as intended.

According to Ørbeck-Nilssen that is why a complex and comprehensive risk man-agement approach needs to be applied to control the risks.

“Offshore oil & gas operations are complex and this complexity in itself rep-resents a significant risk that needs to be managed. This makes it even more critical to have robust risk management covering all risk areas. The Arctic risk reality calls

for a holistic risk management approach which covers all relevant risk areas, from environmental risks to financial and politi-cal risks,” he explains.

Can it be done safelY? Given that further exploration in the Arc-tic will take place, DNV believes that the industry can develop ways to safely explore the Arctic region provided some guiding principles are followed.

“It will be necessary with an extensive collaboration between stakeholders in order to share experience, develop tech-nical solutions, harmonise regulatory

standards and foster transparency of data and knowledge. Further, the exploration should be stepwise, starting with the areas comparable to the best-performing conti-nental shelves and then later moving into even more challenging areas. And finally, any activity should follow a risk-based approach. And all the risk elements should be included in order for the risk picture to be holistic and manageable,” concludes Knut Ørbeck-Nilssen.

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read more about arctic risks here: www.dnv.com/arctic


arctic OPeratiONs

DNV and Statoil cooperate to enhance Arctic competence

DNV and statoil have launched a competence programme that aims to enhance the two organisations’

knowledge about particular arctic challenges.


“Due to Arctic-specific risks such as remoteness, darkness, ice and low tem-peratures, it is utterly important to take a stepwise approach in which we learn and improve from the experience gained. Our complementary roles as operator and risk-management expert in challenging environments are the best reason for shar-ing best practices and enhancing our own expertise,” says Knut Ørbeck-Nilssen, COO DNV Norway, Finland and Russia.

The growing interest in the commercial use and exploitation of Arctic resources is driven by the high demand for energy. To be able to meet the particular Arctic challenges with sound knowledge and safe technologies, Statoil and DNV launched the Arctic Competence Escalator (ACE) programme. This has been developed to enhance the expertise of our own special-ists and to share and improve solutions for specific Arctic issues.

“We will implement the ACE Pro-gramme as a joint effort because we have similar ambitions and backgrounds – and not at least a long history of successful technology collaboration. Although this is an internal programme, the aim to share our developments with the industry,” says Ørbeck-Nilssen.

“Statoil already has many years of expe-rience of Arctic offshore operations, for example in the Barents Sea and at New-foundland in Canada. But the Arctic is a

highly diverse part of the world and oper-ating in the more challenging areas, with longer distances, lower temperatures and ice-covered waters, may require enhanced knowledge and solutions. I hope the ACE programme will be an important driver in obtaining these. Deep insight matched

with respect for the Arctic’s particular conditions will be necessary to manage the risks in this promising but sensitive part of the world,” says Morten Karlsen, head of Statoil’s Arctic Technology Research Programme.

›› the aCe programme was launched to enhance the expertise of statoil and DNV specialists and to share and improve solutions for specific arctic issues.

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arctic OPeratiONs

DNV launches a design framework for floating

structures in ice

DNV-led joint industry project (JIP), ICES-TRUCT, has since 2009 worked to develop a designer-friendly and reliable framework based on the ISO 19906 Arctic Offshore Structure standard.

Per Olav Moslet, Arctic technology research programme director at DNV explains that “The governing design loads for offshore structures in Arctic areas are usually based on interaction with ice, and it is very important that these loads and their effects are treated consistently. Due to the lack of a common industry approach for floating structures in ice, it has previously been difficult for designers to establish the appropriate design loads effects.”

“Because of its nature, ice can gener-ate considerable loads, and structures designed for Arctic operations may look different to structures in open seas. How-ever, ice loads and associated load effects should be treated in the same way as any other environmental load when designing a structure since, in principle, an Arctic offshore structure is no different from any other offshore structure when it comes to assessing adequate structural strength,” he says.

This JIP developed a methodology for determining ice load effects. Rather than having a specific custom-made Arctic design practice for ice loads, the methodology developed is consistent with existing methods for determining other environmental load effects. Consequently, the existing offshore design practice that has been used for several decades in the North Sea and elsewhere can be used for

the design of offshore floating structures in ice.

“The advantage of the new framework is that the same design practice can be used irrespective of the type of structure and environment – Arctic or open sea. That said, the nature and variability of the ice and its complex interaction with structures need to be taken into account,” Moslet says.

The JIP received wide industry support and sponsorship from oil companies, yards and engineering companies, including Transocean, Shell, Statoil, ENI, Repsol, SBM Offshore, Daewoo Shipbuilding and Marine Engineering, Hyundai Heavy Industries, Multiconsult, Keppel Offshore and Marine, Marin, Huisman Equipment and Dr. techn. Olav Olsen. In addition, valuable work-in-kind contribution has been provided by several key international universities and companies such as Pro-fessor Ove T. Gudmestad, Professor Karl Shkhinek, Aker Arctic and the Hamburg Ship Model Basin (HSVA). The project ended in December 2012.

the oil and gas industry has lacked adequate and transparent design practices for floating structures in ice-covered arctic waters. Now, DNV and key industry players have developed an enhanced

design framework for such structures, adapted from existing and established design practices used for open waters in other harsh areas. the approach represents a shift in arctic design philosophy.


›› Per olav moslet, arctic technology research programme director at DNV

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