DNV GL PERSPECTIVES issue 02-2014

SMALLER SCALETECH TO SLASHGAS FLARING

PERSPECTIVESOil and gas industry insight Issue 02 | 2014

ALSO INSIDE:

SMART OPERATORTotal’s Martin Tiffen discusses key roles for innovation amid the new reality of capex and opex control

LIFE EXTENSIONIndia’s ONGC is requalifying ageing offshore assets while Middle East operators respond to similar challenges

BIG DATAIndustry collaboration with academia aims for long-term solution for effective, efficient handling of complex data

2 PERSPECTIVES

CONTENTS

CONTENTS

Disclaimer: DNV GL prides itself on providing accurate information but makes no claims or guarantees about the accuracy, completeness or adequacy of contents in this publication, and disclaims liability for any errors or omissions. The authors’ views here do not necessarily reflect DNV GL’s views.

PERSPECTIVES 02.2014 Published by DNV GL ASNO-1322 Høvik, NorwayTel: +47 67 57 99 00Fax: +47 67 57 91 60

EDITORRobert Stokeswww.cmapsglobal.org

EDITORIAL TEAMCathrine Torp, Robert CoveneyJoyce Dalgarno, Alison CowieRichard Crighton

DESIGN AND LAYOUTThe BIG [email protected]

COVER PHOTO© PhotoDune

© DNV GL AS 2014

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04 NewsThe latest updates from DNV GL

06 Working smarterTotal’s Martin Tiffen discusses cleverer ways for the industry to work amid tight capex and opex control

10 Flexible riser failureResearch calls for further comprehensive studies into this important subsea challenge

12 Subsea pipelines face tough challengeSaipem’s Roberto Bruschi on the need to ensure ‘safe life’ of subsea pipelines in ever harsher conditions

14 Zero gas flaring by 2030Cover story: The World Bank wants an end to the routine flaring of gas associated with oil production. Additional small-scale alternatives to this practice will be necessary if this ambition is to be realised

18 The evolution of marine assuranceThe terms of marine insurance are sparking discussion as price remains king, but relationships count too

22 Life extensionONGC’s Dinesh Kumar explains how the Indian operator aims to requalify dozens of offshore platforms

26 Big dataCollaboration is developing user-friendly software to handle complex data from oil and gas operations

30 PlatformJoint ventures may be the most straightforward way to enter Mexico’s liberalised energy markets

ISSuE 02 | 2014 | PERSPECTIVES 3

WELCOME

New ways of

thinking, more

effective use

of technology,

greater

collaboration and

standardisation

will all play a role

in helping the

industry adjust to

lower margins”

“

TAKING A SMARTER APPROACH

Welcome to the second edition of PERSPECTIVES, a magazine offering insights from DNV GL’s people, customers and industry on topics high on the oil and gas agenda.

Our focus for this issue is on how to develop smarter approaches to projects and operations in a context of rising costs and constrained budgets. More complex operations and projects create tight margins even when the oil price stays at historically high levels. We believe this will become the new normal for the industry. Through our work with customers and industry partners in more than 40 countries, DNV GL is taking an active role in enabling the development of smarter, more effective solutions to enhance production and profitability in a safe and sustainable manner. But smarter oil and gas operations mean more than simply extracting, processing and distributing hydrocarbons more efficiently. New ways of thinking, adding simplicity rather than complexity when innovating, greater collaboration and standardisation will all play a role in helping the industry adjust to this new normal.

Among the features in this edition of PERSPECTIVES, we speak to Martin Tiffen, Total’s second-in-command for global development. He tells us how the company is implementing techniques to reduce the number of people manning assets on the Norwegian Continental Shelf, building greater onshore competence instead (page 6).

This drive to build remote operations from onshore control centres is aided by the growing availability of high-volume digital information that we can now access in real-time from fields and plants. Yet, the task of collecting and interpreting so-called ‘Big Data’ is not easy. Professor Arild Waaler of the university of Oslo outlines his vision for Optique; a four-year, collaborative venture to develop a software platform that will aid decision-making by providing flexible, comprehensive and instant access to large and complex industrial datasets (page 26).

Extending the life of infrastructure has become a strategic priority for many companies targeting smarter operations in mature oil and gas fields. Dinesh Kumar, a general manager at the Institute of Engineering and Ocean Technology, the engineering arm of India’s ONGC, discusses how DNV GL is supporting the requalification of the company’s platforms, specific to conditions offshore India but with potential for much wider application (page 22).

The articles in this edition of PERSPECTIVES – including our cover story on efforts to reduce gas flaring (page 14) – build a picture of an industry that is in the forefront – tackling the changes head on. I hope that you find them insightful.

Elisabeth TørstadCEO, DNV GL – Oil & Gas

DNV GL headquarters, Høvik, Norway

4 PERSPECTIVES

SUBSEA FACTORY COLLABORATION

Oil and gas operators are being urged to collaborate on a project to standardise interfaces for seabed processing plants. The Subsea Factory Interfaces Standard initiative is being led by Norwegian operator Statoil with DNV GL running the joint industry project (JIP).

Subsea processing systems are often tailor-made to field-specific requirements and components. The bespoke installation tools required, often on specialised vessels, add to cost. Coupled with extensive qualification programmes, it means developing these systems is often a long and costly process. The project aims to reduce the expense of new projects and to increase the number of business cases successfully made for subsea processing.

Also known as the Subsea Factory Project, it will seek to develop open industry standards and will leave ample room for innovation whilst standardising how relevant technology is packaged, connected and installed.

“Think of the modules as LEGO bricks,” said Margareth Øvrum, Statoil’s executive vice president of technology, projects and drilling. “By having standardised module dimensions, which may be assembled using standard tie-ins, we can combine technology from different suppliers and also cover several needs through subsea solutions.

“Standardisation will be important to secure a strong and coordinated approach to the supplier industry in order to achieve the goal of more profitable subsea developments.”

INTERACTIVE ARCTIC RISK MAP IS LAUNCHED

The map provides stakeholders with a comprehensive tool for decision-making and transparent communications across offshore and maritime activities in the Arctic.

In a user-friendly layout, it presents multiple dimensions such as the seasonal distribution of ice; metocean (physical environment) conditions; sea-ice concentrations; biological assets; shipping traffic; and oil and gas resources. Depending on season and location, a safety and operability index is included to track variance in factors that impact the risk level. A location and season specific index has also been developed showing the environmental vulnerability of marine resources in the event of an oil spill.

Børre Paaske, project manager at DNV GL – Oil & Gas, said: “The Arctic is not a monolithic area and the risk picture varies accordingly. As a result, the consequences of an accident in the Arctic would likely be more severe in some areas than others. Stakeholders therefore need a sound decision-making basis for understanding the risks associated with Arctic development and transportation. The DNV GL Arctic Risk Map can help facilitate transparent discussions to address the many dilemmas related to activity in the region.”

The Arctic Risk Map is available to download at: www.dnvgl.com

NEWS

AVOIDING JACKING SYSTEM FAILURE

Attendees at the Abu Dhabi International Petroleum Exhibition & Conference (ADIPEC) 2014 will be the first to take part in a global knowledge-sharing programme on DNV GL’s latest recommended practice (RP) to avoid jacking system failure.

In addition to experience-exchange sessions and presentations at the event, the company is actively seeking input for further development of the RP in cooperation with other industry bodies.

The new recommendation provides guidance to ensure correct and safe functioning of rack and pinion style jacking systems. The aim is to reduce downtime and the risk of gear failure, thus reducing cost and increasing availability throughout the asset’s life.

“The consequences of jacking gear failure can be severe,” said Michiel van der Geest, project manager, DNV GL – Oil & Gas.

“While the problem is acknowledged by the industry, correct maintenance and inspection of jacking systems have proved challenging.

“Bringing together industry players in neutral territory has allowed us to openly discuss issues and challenges related to jacking gears.”

DNV GL will be exhibiting in Hall 9, stand 9212 at ADIPEC 2014.

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Børre Paaske, DNV GL


The acquisition in May of Norway’s Marine Cybernetics, a provider of third-party testing of computer-based control systems, will expand DNV GL’s scope of services in the offshore and maritime industries.

Established as a 2002 spin-off from the Norwegian university of Science and Technology (NTNu), the company introduced Hardware-in-the-Loop (HIL) testing to maritime and offshore industries. HIL significantly reduces the risk of accidents, off-hire costs, and non-productive time due to software-related issues.

The decision to invest in Marine Cybernetics was driven by the increasing importance of software dependent systems in ensuring safe, reliable and efficient operations.

A requirement for software-system certification was introduced into the offshore classification rules by DNV GL some time ago. The market for the third-party testing and certification of

NEWS

US FLOATING FACILITIES ROADMAP

In the first comprehensive overview of its kind, DNV GL has mapped out what is needed to comply with uS Coast Guard (USCG) requirements to operate floating oil and gas facilities in American waters.

The roadmap document – ‘Verification for compliance with united States regulations on the outer continental shelf’ – eases uncertainty among operators over requirements and accepted rules and standards detailed by the Code of Federal Regulations on the operation of FOIs, FSOs and FPSOs. It is an example of how DNV GL acts as a bridge between industry and regulators.

“Including all the relevant information in a single document creates a clear path for compliance,” said Paal Johansen, who leads DNV GL’s classification business in the Americas. “Many operators and owners have welcomed the roadmap. Owners have expressed a strong desire to freely choose a classification society for floating offshore installations in American waters. This document is further proof that they can do so and be confident in the entire regulatory process.”

The US Floating Facilities Roadmap is available to download at: www.dnvgl.com

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control systems is currently small, but has huge potential.

“We see that an increasing number of incidents, many of them severe, are caused by software-related issues,” said Remi Eriksen (pictured right), DNV GL group COO and executive vice president, seen here shaking hands with Stein Eggan, CEO of Marine Cybernetics. “This will be a game-changing platform to enhance safety and increase operational efficiency in the offshore and maritime industries. A longer-term goal is to use the competencies and technologies in other asset heavy and software intensive industries, such as the power generation, transmission and distribution industries.”

A global roll out of HIL testing services via DNV GL’s worldwide network is underway.

Marine Cybernetics is now an independent business unit within the group and after a transition period of three years, there is the option to attain sole ownership and fully integrate Marine Cybernetics into DNV GL.

DNV GL ACQUIRES MARINE CYBERNETICS

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6 PERSPECTIVES

Working smarter in an era of constrained capex and rigorous opex control demands full contributions from technology, resource planning, collaboration and, where possible, standardisation.

So said Martin Tiffen, speaking as MD of Total E&P Norge, the French international oil and gas group’s Norwegian subsidiary, shortly before becoming the second in command at Total’s global development function in Paris.

“The whole industry is under the same pressures,” he told PERSPECTIVES. “There is a flat perspective in hydrocarbon pricing, costs are rising 8%–10% a year and governments are tending to take more (in revenues). We cannot control some factors, so we have to be smarter about the ones we can control.”

Norwegian field leads the wayTotal has invested around uSD2 billion per annum on the Norwegian Continental Shelf (NCS) in the last five years. The 240,000 barrels of oil equivalent that it produced on the NCS in 2013 will be boosted by projects including the Martin Linge oil and gas field, which is due to start up in 2016.

Martin Linge is being developed through a standalone platform, taking electrical power from shore, together with a floating storage and offloading unit. The platform integrates a wellhead,

A TOTAL APPROACH TO SMARTER E&PIntelligent exploration and production involves the company and its entire supply chain, says Total’s Martin Tiffen

Oil and gas also

needs to look

outside the industry

for examples of

smarter working.

Some crossover in

how technologies

are applied is

possible if you

can see it”

Martin Tiffen, number two in Total’s global development function

“

WORKING SMARTER

production and living quarters. Drilling will be by a separate, heavy duty, jack-up rig.

The project lays down a marker for the industry in the way the field is being operated and controlled. At Total’s main office onshore in Stavanger, a central control room duplicates the one offshore on Martin Linge. Operating the field will involve 22 people, some working on the traditional two-on four-off offshore cycle, and some spending six months each year working in the onshore control room. With a classical offshore-only operation, an offshore workforce of around 70 people would have been required.

“All data being generated offshore will be sent back in real-time onshore through fibre optic cable. Platforms are no longer autonomous islands. If you have all the data onshore, you can use onshore competence to process the data. This both reduces costs and shifts more tasks back on land,” Tiffen explained.

“This operating philosophy was incorporated into the design and build stages of the project, allowing minimal manning for reasons of economics and safety. For Total, it is the first time remote operation control has been pushed so far. This has been possible because we have been able to build it into platform design, which would not be easy if it were a retrofit.” >

PHOTO DNV GL


WORKING SMARTER

8 PERSPECTIVES

WORKING SMARTER

Continual improvements in information technology and sensors also deliver benefits to operational performance, Tiffen added. For example, equipment, drilling and subsurface parameters can be made available in real-time and may be sent anywhere in the world, including to external partners.

“If you need expertise or diagnostic capacity, you can get it onshore without necessarily flying someone offshore to the platform or rig. This allows you to make better decisions in a shorter timeframe, which is important when you are racking up rig and well costs. We are seeking to push the boundaries in many domains. But the proof of the pudding is in the eating: I don’t want to over-promise, and it will take a lot of work to deliver our vision.”

It is this kind of thinking around technology solutions that Total values as it embarks on a three-year cost containment drive across the group’s global operations. The aim is to boost returns from its substantial investment programme of recent years.

High predictability creates efficiencies in all parts of the supply chain. It is vital to avoid logistical jams and higher costs that could be caused by late contracting for equipment, vessels and services in capacity constrained markets, Tiffen observed in discussing how collaboration can contribute to being smart.

“We need to anticipate and liaise closely with suppliers and contractors in good time. Contractual relationships are part of working smarter. This is work in progress because what works in one part of the world, or over time, varies.

"So, you have to be flexible and work with contractors with good knowledge of the local environment and work in partnership to deliver.”

Scope for standardisationStandardisation is a regular item on the industry checklist when cost containment is being debated, though it can pull in a different direction to technology development. “One size does not fit all, but there is tremendous scope for standardisation and simplification,”

Tiffen commented. He offers the example of subsea Xmas trees. Oil companies each had their own requirements for forgings used in subsea Xmas trees, with no standard requirement for metallurgy or inspection during fabrication. So a tree manufacturer could not have a set of forgings ‘on the shelf’. Following a joint industry project led by DNV GL, there is now a common standard that should bring shorter lead times and more standardisation without sacrificing quality.

Standards require effortTiffen believes that Total’s company standards and the lessons it has learned provide a good platform for smarter working.

“But you have to go further than that. You can have a relaxation or waiver and that also helps standards to evolve. Could we have more common standards with ExxonMobil, Statoil or whoever? I kind of think we should, but even that involves more effort than you might imagine.

"It is ultimately desirable to evolve the API or other standards so everyone can

PHOTO TOTAL

The installation of Martin Linge's yellow jacket is keeping Total on course to start production in 2016 from the innovative field development


WORKING SMARTER

use them, but it is permanently a work in progress.”

Others standards relating to aspects of Xmas trees include the recently issued DNVGL-ST-0035:2014-08 covering subsea equipment and components.¹

Look beyond the sector“Oil and gas also needs to look outside the industry for examples of smarter working,” he said. Citing a talk by the mayor of Houston, uS, at the ONS Conference and Exhibition in Stavanger, Norway this year, Tiffen noted how the American city’s key sectors – oil and gas, aerospace and medical – all use valves, fibre optics and remote monitoring. “Some crossover in how technologies are applied is possible if you can see it.”

He also raised a question about the way consumer orientated businesses offer continuous improvements without necessarily increasing costs. “Look at aviation. It still costs maybe uSD1,000 to fly from Europe to Singapore; but compared with 20 years ago, the planes are bigger and better, the food is

improved, there is in-flight video and so on.”

Contrasting this with what happens in oil and gas, he added: “Take drilling, we do not seem to improve our well durations at the same rate. We need to ask why we are an industry that cannot improve as fast as others.”

Positive outlook That said, his 10-year view of where things are headed suggests that oil and gas will continue to benefit from incremental and step-change advances in its technological capabilities.

“Imaging technology has dramatically improved both in terms of acquisition and processing,” he said by way of illustration. On Martin Linge, three seismic surveys were conducted within 10 years to reflect advances in this technique. "Each one was an order of magnitude better than before, in the same way that I saw ultrasonic scans getting clearer each time one of my daughters was on the way!”

1 Standard DNVGL-ST-0035:2014-08 Subsea equipment and components, DNV GL, is available as a PDF free of charge at: www.dnvgl.com

Graduating with a degree in engineering science in 1984, Martin Tiffen has spent his entire career in upstream oil and gas, eight years initially with Shell, then the last 22 years with Total, working in a variety of technical, business and managerial roles mainly in Northwest Europe and the Far East.

For more than five years until August 2014, he was managing director for Total E&P Norge in Norway, and is very proud to be associated with the Martin Linge field development.

In September 2014, he took up a new role in Total’s Paris head office as the number two in the global development division.

10 PERSPECTIVES

STUDIES PROBE FLEXIBLE RISER FAILUREThe technical root cause of this issue is still a conundrum, Bjørn Søgård explains

FLEXIBLE RISER FAILURE

The industry

accepts that

there has been

an unacceptable

number of

failures”

Bjørn Søgård, segment director, subsea and floating production, DNV GL

“

In 2011, 63 people were evacuated from the Visund platform in the Norwegian Continental Shelf (NCS) after gas escaped from a leak in a riser that had been closed for inspection. Field operator Statoil immediately set up a specialist team to investigate, while Norway’s Petroleum Safety Authority (PSA) conducted its own report. No-one was injured, environmental pollution was minor. The incident was caused by a new failure mode unknown to the industry, giving another example of the challenges of understanding the complex behaviour of flexible pipes.

The Statoil taskforce brought in to investigate the issue involved 20 leading riser experts¹ over 18 months. The group consisting of Statoil, 4Subsea and DNV GL was assembled to share information to solve issues around failure of multilayer polyvinyl difluoride (PVDF) risers.

Flexible risers are an enabling technology for floating production in harsh environments. These pipes encompass a layered structure in which the various materials have functions such as: withstanding external and internal pressure, coping with tensile forces, preventing hydrocarbon leaks and protecting against seawater.

Norwegian statistics for 2010-13 show at least 1.5% probability of failure per

1 Statoil press release, ‘Routines improved for operation and maintenance’, September 20112 ‘PSA begins flexible risers study (Norway)’, Subsea World News, January 20143 4Subsea report. ‘Un-bonded flexible risers – recent field experience and actions for increased robustness’, 2013

PHOTOS DNV GL

riser per operational year, according to the PSA. There are multiple causes, but the underlying factor is several years of inadequate appreciation of the complexity of flexible pipes and possible failure mechanisms.

Earlier this year, the PSA commissioned a study to update knowledge of un-bonded flexible risers in Norway.2 DNV GL is also calling for more comprehensive studies in this area through industry collaboration, across commercial boundaries and barriers. We believe that this could increase confidence in the sector and open the market to innovation and standardisation in riser technology.

In 2013, there were about 300 flexible risers offshore Norway. Many were subject to high pressures and temperatures, large fluctuations in operating parameters, and high dynamic loadings.³ This is a significant reliability challenge. According to an independent engineering company, more than 25% of NCS risers have been replaced historically and few have met their originally predicted service life.

In its 2012 report ‘Risk Level in Norwegian Petroleum Activities’, the PSA acknowledged that the frequency and significance of flexible riser incidents were rising and higher than for steel risers.


FLEXIBLE RISER FAILURE

Risers that experienced carcass collapse were constructed with three layers of PVDF polymer material.4 Issues related to carcass collapse in flexible risers with multiple layers of PVDF have been known since the early 2000s. However, being able to predict, detect and understand carcass collapse and tearing has been further investigated in ongoing work continuing from the taskforce established by Statoil in 2011.

One outcome of the 2011 Statoil investigation was a paper presented last year by co-authors Statoil, 4Subsea and DNV GL.5 It explained the nature of the carcass-tearing problem and suggested load model and operational policy for mitigating risk of new failures. The paper called for further inspection and carcass monitoring to avoid pollution or a safety critical situation, and for new risers to have greater robustness towards carcass collapse and tearing.

The paper and discussions resulting from both the Statoil and PSA investigations have gone some way to address the technical complexities of the issue and to consider the need for enhanced flexible riser and flowline technology at the subsea project design stage, but more is needed.

In a major drive to improve quality and reduce costs, the oil and gas industry now has its first standard to certify subsea equipment and components.

The goal of the DNV GL standard is to streamline quality control and manufacturing processes and to reduce pressure on global supply chains. This will ultimately shorten lead times and help to deliver projects on schedule.

The certification scheme also aims to help the interpretation of existing API and ISO standards. It will provide operators with confidence that fabrication quality is being controlled and assured throughout the industry.

Bjørn Søgård, segment director, subsea and floating production at DNV GL – Oil & Gas, said: “Standardisation is widely agreed to be the solution to address many inefficiencies in most industries. For operators, this standard will reduce costs without sacrificing quality, innovation or safety. For suppliers, it will increase predictability and enable the strategic stocking of long-lead items.”

The certification of subsea equipment and components standard (DNVGL-SE-0045) is available to download at: www.dnvgl.com

4 ‘Hydrocarbon leak from flexible riser – investigation report’, Officer of the Watch, July 20135 ASME 2013: OMAE 2013-10210, ‘Carcass failures in multilayer PVDF risers’, Knut-Aril Farnes,

Claus Kristensen, Steinar Kristoffersen, Jan Muren and Nils Sødahl

STANDARD PAVES WAY FOR SUBSEA CERTIFICATION

Flexible risers are an enabling technology for floating production in harsh environments

12 PERSPECTIVES

PIPELINES CONFRONT NEW EXTREMESContractors are investing in responses to ever more challenging demands on pipelines and pipelay

SUBSEA PIPELINES FACE TOUGH CHALLENGE

PHOTOS SHUTTERSTOCK, SAIPEM SpA

Demands on subsea pipelines are increasingly complex as they operate in remote and harsh environments, and transport increasingly aggressive products across longer and/or deeper sealines.

Lay vessels must align wider and heavier pipelines, and new concepts such as pipe-in-pipe (PIP), to specified routes in difficult conditions such as steep slopes, narrow corridors, rough seabeds and harsh metocean. Critical inline structures must meet stringent targets.

“Such demands require high capacity equipment to handle, hold and protect pipelines during installation and to monitor lay parameters in real-time,” said Roberto Bruschi, vice president of advanced engineering services and innovation technology projects at leading international contractor Saipem SpA, Italy.

Continuous investment in new and upgraded vessels is a key part of Saipem’s strategic response to offshore market needs.

The art of smartThe Castorone dynamically positioned (DP) deepwater laying ship for operations in extreme environments, and the Saipem FDS 2 (DP) field development ship, illustrate this. Castorone monitors lay

The most important

consideration for

Saipem is safety”

Roberto Bruschi, vice president advanced engineering services and innovation technology projects, Saipem SpA

“progress. It displays easy-to-read charts and data generated by integration of instrumentation and advanced calculation, such as real-time configuration of pipelines on the stinger and along the lay span.

“The stinger is really smart, not just a steel truss,” Bruschi said. The stinger tip can extend up to about 40 metres (m) aft (rear) of Castorone, and more than 90m below the sea in steep lay configuration, to guide pipelines carefully. This, and skilful operators, maintains the working level of the pipe within allowance limitations, right up to seabed touch down.

Stress on pipelines at points along the stinger and, after exit, along the lay span is continuously controlled. “Monitoring the working level of each part of the equipment can be quite crucial during the most demanding operations and therefore for the laying season.” This enhances control of pipe-laying operations and schedule, and allows speedy responses to unexpected events that cannot be excluded in open sea.

Powerful computing underpins Bruschi’s belief that future challenges can be met: “I started in the industry in 1980, and computers are now doing things 100 or even 1,000 times faster.”

Applications include numerical simulation of most conditions and scenarios. Examples include the pipe and the lay vessel position near seabed targets under a specific setting for laying parameters, and for dynamic conditions under wave-induced oscillations and slow drift counteracted by DP.

Design for safe lifeOn the mechanical design, Bruschi noted “a general consensus” around reliability-based design criteria and load-resistance factor design, and on continuous upgrading of design to reflect research and development.

However, he argued that for environmentally sensitive and remote locations, criteria for applying design


SUBSEA PIPELINES FACE TOUGH CHALLENGE

Saipem's deepwater laying ship Castorone operates in extreme environments

to new applications should include assessment of consequences to health, property and environment across the widest range of factors and for the pipeline’s lifecycle.

“It is not a case of just modelling the capacity of the actual material to perform in normal conditions,” Bruschi said. Numerical modelling should anticipate and verify line pipe capacity to handle realistic demands under severe environmental events such as wave storms, geohazards or ice gouging, he explained.

“It is about safe life rather than fail safe. The most important consideration for Saipem is safety. This applies to every element of planning, design and pipe-laying operations, and across all our people and levels of management. We have put a lot of effort into training and competency throughout the organisation.”

Robustness is the keyFor pipelines to be safe, cost-effective and efficient 20 to 50 years on, the key is “robustness” throughout the lifecycle, Bruschi stressed.

“With pipelines in shallow to medium depths, across crowded and near-to-coast offshore basins, you have the possibility to intervene. You have a state

of preparedness that can maybe accept a minor fail where it is not jeopardising the structural integrity and carrying capacity in the short-term, without the need to intervene quickly.”

If intervention is needed, then vessels and other resources can be lined up in good time. Experiences in the North and Mediterranean Seas help to understand criticality. “But what do you do if you have a winter season incident at Sakhalin or in the Barents Sea?” he asked. “Then you have to do something involving a huge spread of very specific working vessels in a very short time, and vessels are in short supply. Would you not prefer to have a robust solution from the beginning?”

An increasingly integrated multi-disciplinary approach across surveying, design and installation is inevitable in his opinion, as is collaboration between industry, academia and others. His view of DNV GL’s role in this ecosystem is that it has “a big ear” to what is happening worldwide through clients, and through DNV GL’s joint industry projects (JIPs) and the Pipeline Committee and Innovation Forum.

Standardisation, along the lines of the DNV-OS-F101 Offshore standard for submarine pipeline systems, can help

to raise quality, reduce risk and lower cost. However, Bruschi also pointed out that responses to needs in deep waters off Brazil, for example, may be very different to those off West Africa.

Roberto Bruschi’s presentation at DNV GL’s Pipeline Innovation Forum is available to download at: www.dvngl.com

14 PERSPECTIVES

NEW DRIVE TO END ROUTINE FLARINGSmall-scale alternatives to burning off gas from oil production are moving centre stage

ZERO GAS FLARING BY 2030

PHOTO PHOTODuNE

If investments

in making gas

available for

local energy

markets are not

forthcoming,

everyone loses”

Bjørn Håmsø, programme manager, Global Gas Flaring Reduction Partnership

“

The catalysts and sources of climate change are attracting increasing attention, debate and concern. The flaring of natural gas associated with oil production is a highly visible example.

Approximately five per cent of world annual gas production is being flared or vented worldwide, noted Martin Layfield, gas segment director, DNV GL. “That is equivalent to about 110 to 140 billion cubic metres (bcm) of gas.¹ It equates to the combined gas consumption of Central and South America in 2013.”

The World Bank estimates that flaring 140bcm would cause more than 350 million tonnes (mt) of CO2 release into the atmosphere. If this could be harnessed for power, for example, it could produce 750 billion kilowatt hours per year, more than Africa’s entire annual consumption.

Zero flaring callAs PERSPECTIVES went to print, the World Bank was planning to launch a ’Zero Routine Flaring by 2030’ initiative, calling on governments and companies to achieve that in the next 15 years.

New technologies – or smarter uses of existing ones – are one answer, but formidable, non-technical hurdles include investment, and regulatory and legal frameworks. However, the target is realistic, according to the Global Gas Flaring Reduction Partnership (GGFR), a World Bank-embedded organisation of about 30 governments and oil companies, including virtually all leading international oil companies.

“We believe it is achievable,” said Bjørn Håmsø, GGFR’s programme manager. “We have discussed the initiative in great

detail with international and national oil companies and governments. Some already have flaring policies, but the initiative would shed additional light on their good work, and add impetus and scope to it.”

Success will depend on a substantial number of companies and governments endorsing it, Håmsø added. “We expect that to happen. It would level the competitive playing field for associated gas utilisation for new oil field developments, and create momentum to achieve the initiative’s goal.”

Using flare gas The proposed initiative tries to focus governments, oil companies and development institutions on actions enabling economic utilisation of flared gas.

“In Nigeria, for example, part of the problem is a regulated gas price of about uSD1 per one million British Thermal units to power plants,” Håmsø said. “This is a small fraction of the price in the uS and Europe. There is an obvious social aspect to domestic gas and electricity prices, but there are ways to target assistance more directly to vulnerable groups. If investments in making gas available for local energy markets are not forthcoming, everyone loses.”

In contrast, one business model in western Siberia, Russia, is to invest in a gas separation plant, shipping heavier components – propane, butane and natural gasoline – to market, while putting lighter ones, mostly methane, into a small power plant. Håmsø observed: “There are efficient reciprocating engines available for small-scale production of power >

1 Satellite data from US National Oceanic and Atmospheric Administration analysed by the World Bank (see table opposite)



Gas flaring (bcm¹): Top 20

Rank/CountryYear2007

Year2011

Change% of

2011 total

01 Russia 52.3 37.4 -14.9 26.7

02 Nigeria 16.3 14.6 -1.7 10.4

03 Iran 10.7 11.4 +0.7 8.1

04 Iraq 6.7 9.4 +2.7 6.7

05 uS2 2.2 7.1 +4.9 5.1

06 Algeria 5.6 5.0 -0.6 3.6

07 Kazakhstan3 5.5 4.7 -0.8 3.4

08 Angola 3.5 4.1 +0.6 2.9

09 Saudi Arabia4 3.9 3.7 -0.2 2.6

10 Venezuela 2.2 3.5 +1.3 2.5

11 China 2.6 2.6 0.0 1.9

12 Canada 2.0 2.4 +0.4 1.7

13 Libya 3.8 2.2 -1.6 1.6

14 Indonesia 2.6 2.2 -0.4 1.6

15 Mexico5 2.7 2.1 -0.6 1.5

16 Qatar 2.4 1.7 -0.7 1.2

17 uzbekistan 2.1 1.7 -0.4 1.2

18 Malaysia 1.8 1.6 -0.2 1.2

19 Oman 2.0 1.6 -0.4 1.2

20 Egypt 1.5 1.6 +0.1 1.2

TOP 20 TOTAL 132 121 -11.0 86.4

Rest of the World 22 19 -2.0 13.6

GLOBAL FLARING 154 140 -14.0

The most recent World Bank estimates from US National Oceanic and Atmospheric Administration satellite data show rising American shale oil production driving up flaring there. Russia still flares by far the most, but has been reducing this.

Notes1 bcm = billion cubic metres2 includes North Dakota shale fields3 was reported as much lower4 includes Saudi share of Neutral Zones with Kuwait5 was reported as much higher

16 PERSPECTIVES


from gas. This power can often be returned back to the oil production site.”

If a local electricity market is saturated and an operator is ‘stranded’ with gas far from larger markets, gas-to-liquids (GTL) solutions could come into play, Håmsø said.

“Liquids such as diesel, gasoline, liquid fertiliser and others are easily transportable. If the operation is near an oil pipeline, manufactured synthetic crude could be injected into the pipeline flow. The issue is to get costs and risks reduced in small-scale GTL plants: these are technically complex and require highly skilled staff, which often is an issue as well.”

He expressed optimism that such risks and costs will decrease: “A couple of years ago, we felt there were only a dozen or so [small-scale GTL plant] companies worth monitoring. Today, that number has doubled.” Innovation is driven particularly by the uS shale oil boom and an associated boom in flaring, he observed.

The Bakken effectThe story of development in North Dakota’s Bakken basin, a shale oil play in America, illustrates this. Twenty-

nine per cent of gas produced in the Bakken is flared at wells, according to the university of North Dakota’s Energy & Environmental Research Center (EERC).2 Nearly 50% of that is from wells connected to gas-gathering networks lacking capacity to handle more. As production grows though, so does the economics of infrastructure to handle associated liquids-rich gas from more accessible drilling areas.

New guidelines proposed by the industry in North Dakota earlier this year set targets for flaring at above 20% of all gas produced by January 2015. This reduces further by 2020 and, potentially, further again beyond that year.

Scale of responseGlobal oil and gas operator Hess Corporation, a large producer in the Bakken, has continually expanded its local Tioga Gas Plant. It recently doubled Tioga’s near 100 million standard cubic feet per day (mmscfd) operational capacity to produce propane, methane, butane, natural gasoline and industrial feedstock ethane.

Hess said the percentage of natural gas flared at its Bakken wells had fallen from about 25% before Tioga was expanded, to 15%–20% today, nearly a year after

the revamped plant became fully operational. Tioga was processing about 120mmscfd this spring. Hess estimated that combining its own and third-party gas would raise that soon to at least 250mmscfd, with potential to exceed 300mmscfd. It is working on four new gas gathering projects.

Tioga is a large-scale solution made viable by substantial gas supply within relatively easy reach and with robust markets for its products. Many remoter locations and poorer economies with weak markets for gas or gas liquids need cheaper, more compact answers.

“Existing solutions are mature for large-scale applications, but most flaring is very small-scale,” said Martin Layfield. “We need innovation in applying associated gas to energy intensive processes, such as air separation and water desalination, though some solutions might be immature for near-term implementation.”

A DNV GL team has talked to providers to update understanding of technologies then work up commercially viable concepts for gas capture in real locations and conditions on- and offshore.

“We are covering a range of flow rates, gas compositions, geographical locations

PHOTO RICHARD HAMILTON SMITH, CORBIS

The oil drilling boom in North Dakota's Bakken basin is driving innovation aimed at creating affordable alternatives to flaring



2 Energy and Environmental Research Center, university of North Dakota: www.undeerc.org3 ‘Removal and recovery of Natural Gas Liquids using UCARSORB™ NGL adsorbents’, Dow Chemical Company technical note, Jan 2014

JOINED-UP THINKING NEEDED

Tackling flaring is not just about technology. Bjørn Håmsø, programme manager at the Global Gas Flaring Reduction Partnership (GGFR) stresses a need to win over policy makers and foster collaboration with industry and governments.

“In the uS, state governments and companies are working together to address flaring,” he observed. “The US government is a GGFR partner, so is the government of Alberta, Canada. Many GGFR partner countries have sent teams to Alberta for training, or have received experts from Alberta to help develop gas flaring solutions.”

GGFR is better positioned to make a difference when governments are unable to manage their energy sectors, particularly through effective regulation, he added.

“Traditionally, the World Bank has focused on the power sector,” he said. “With the flaring initiative, it will also look further upstream to secure efficient utilisation of a country’s energy resources.”

and so on,” said Robert Rawlinson-Smith, director of technology programmes, DNV GL. “The different combinations represent current flaring situations and require very diverse technology solutions. We are also considering how to make processing plants modular and flexible, allowing them to be used at different locations as wells deplete.”

Innovation in actionEERC has a database of vendor-provided information on small-scale gas use technologies capable of impacting flare reduction.

It has also assessed some current technologies and their economics for small-scale gas processing to recover Natural Gas Liquids (NGLs), and for using associated gas for power production, transportation fuel and chemical production.

It concluded that “innovative approaches to effective implementation” were needed. Some are already being deployed, tested or proposed.

An example on the processing side is Dow Chemical Company’s adsorbent-based technology, UCARSORB, which removes NGLs from wellhead gas.³ “This has potential to provide a relatively

smaller and mechanically simpler technology, compared to compression and refrigeration, to process gas at small scale,” EERC senior research manager Chad Wocken said.

Alternative use of gas in the Bakken is illustrated by operator Statoil. “It is taking advantage of its bi-fuel equipped [diesel and natural gas] drilling rigs by combining well site gas-processing equipment (GE’s CNG In A Box) and local compressed natural gas distribution through Ferus Natural Gas Fuels (Denver, uS) to get stranded gas to drilling sites with high fuel demand,” said John Harju, EERC associate director for research.

“This allows valuable NGLs to be recovered and marketed. It also creates a methane stream better suited for bi-fuel engines and alleviates the need for temporary gas lines from producing locations to drilling locations.” Across all operators, as many as 80 drilling rigs in the Bakken may have bi-fuel technology, Harju estimated.

© C

ORB

IS

18 PERSPECTIVES

PRICING POSES QUESTIONS FOR MARINE ASSURANCEThe cost and terms of temporary phase marine insurance have come under debate

PHOTO DNV GL

Our clients like

a good price,

but many see

insurance buying

as a long-term

relationship and

want to be sure

insurers will

pay if there is a

terrible event”

Francis Lobo, head of engineering – energy, Catlin Group Limited

“

THE EVOLUTION OF MARINE ASSURANCE

Marine insurance for offshore oil and gas projects has become increasingly price-driven in recent years, raising questions about the balance between the cost and depth of assurance. This applies along the chain from fabrication, through transportation to an eventual field location, and to aspects of offloading and installation.

Two main factors lie behind this market ‘softening’, according to Chris Graham, new business development leader on the offshore construction side at insurance broker Aon. Its clients range from small independents and contractors, to oil and gas majors. He said: “We have seen a vast increase in global capacity for energy insurance over the past five years as capital providers sought returns outside traditional financial markets. Also, there have been no significant losses [to insurers], and a series of benign hurricane seasons.”

Technological advances, more robust practices and greater experience may also have contributed to lower prices. Better weather forecasting, more powerful tugs, dynamic positioning and the rise of IT have transformed perceptions of what is possible and the attendant risks.

In the more than 50 years since Noble Denton played a role in establishing marine assurance in the North Sea offshore industry, prices have dropped significantly. Noble Denton, a marine and offshore technical advisor, is now part of DNV GL.

“Much of what the industry does has just become so much more familiar,” said DNV GL’s Richard Palmer, regional manager for Australia, New Zealand and Papua New Guinea. “With familiarity, maybe some assured parties start to perceive marine warranty services almost as a necessary evil.”

A 50-year perspective also points to technical precision and the consequences of equipment failure as key factors, said Norm Dimmell, leader for DNV GL’s Noble Denton marine assurance and advisory service area.

“Contrast sticking a pipe through the seabed in 25 metres (m) of water in the 1960s with doing it at more than 1,000m depth today. In the early days, there was less aversion to things going wrong because the consequences would not have been so disastrous.”

Now, “even a nick to the side of an asset could be catastrophic” because a vessel or unit is designed with more precision for a specific task and to a specific operating limit, Dimmell added. “Furthermore, as technology and analytics have increased, we reduced the inherent redundancy in design. That is reflected in more robust regulatory frameworks, developed in response to incidents.”

Generally, underwriters now take a more technical approach to analysing risk offshore. With many factors influencing rates, brokers choosing the right underwriter to lead the project and gain the broadest coverage at the most >



20 PERSPECTIVES


competitive terms need a clear technical understanding of the risk and that particular underwriter’s appetite for it, Aon’s Graham observed.

underwriters would like to insist on the highest levels of due diligence and risk management within offshore construction. “However, although we strongly advocate providing as much information as possible, with the market at its softest for some years, and in appreciation of commercial constraints that clients may have, this has not been enforced in every case,” Graham explained.

In this market, the due diligence clause within the standard offshore CAR wording (WELCAR 2001) has typically been deemed sufficient by underwriters without adding further subjectivities or warranties, he added.

One underwriter’s engineering chief acknowledges this, but sees room for improvement in offshore construction. “Many companies do not seem to manage the marine phases very well,” said Francis Lobo, head of engineering – energy, at Catlin Group Limited’s London underwriting hub for insurance and reinsurance. “They have established processes, but silos exist within project

teams and gaps between different contractors. Larger companies try to close these gaps, but we still see weaknesses in due diligence and risk management in these phases.”

The market will turn Lobo expects market softening to reach a point where companies who do not maintain underwriting discipline will start to sustain losses to the extent that backers will withdraw capital. There could be a hiatus event such as a Macondo or, more likely, a large windstorm resulting in pan-market losses, causing the market to turn.

“One must also consider the role of assured parties’ captives [company-owned insurance vehicles],” Graham added. “Over the last few years, such entities have increased their capacity and appetite for construction risk.”

If captives opt to rein in this capacity, or decide not to follow the market further down, it would likely result in less market competition, with the potential to generate a rates increase, particularly on larger projects, he explained.

The soft market has prompted discussion on whether depth of assurance could be eroded longer-term.

For insurance to be valid, an assured party must appoint a marine warranty surveyor and comply with the scope of warranty work agreed with the lead underwriter.

Through technical reviews and site attendance, such surveyors independently survey marine operations – structures, objects, vessels and equipment, systems, and procedures – to evaluate risks and assess the feasibility of operations. DNV GL sets industry guidelines for such warranties through its Noble Denton marine assurance services.

The scope of a marine warranty survey is the “eyes and ears” of the underwriter, Palmer said. “The surveyor’s responsibility is entirely to the underwriter.”

Detailed scopes allow underwriters to ensure, indirectly, high levels of due diligence and care. Operators may anyhow have to look beyond lower insurance costs, if they are to ensure safety and sustainability while working increasingly in challenging environments.

Aon’s Graham said: “We advocate using a marine warranty surveyor, but negotiate with underwriters to minimise the scope that forms part of the policy, thereby limiting potential for breach of warranty and avoidance of coverage.”

Insurance costs reflect underwriters' views of risk for each element of the project chain from fabrication and transit onwards

PHOTOS KVAERNER, PETROBRAS


HOW PRICING RISK WORKS


The price of offshore construction insurance reflects rates for each project element. Project risk during onshore fabrication is generally less than during transit, installation, hook-up and commissioning, because of higher consequences and probabilities of loss in these later phases. underwriters price this accordingly. Standard rates may be applied to each phase, but with adjustments made up or down after consideration of risk factors. Rate differences for offshore installation may depend on water depth, contractor quality, and the method and type of installation; for example, a North Sea fixed platform or a tension leg one in Gulf of Mexico. The use of a marine warranty surveyor (see below) may also affect the rate.

A fabrication rate could be heavily discounted if the yard is well known, and has a good reputation and loss history. underwriters’ personal experiences and knowledge shape what they charge. Knowing this, experienced brokers help source the right insurance for a client’s needs at levels of risk management, due diligence and pricing on which all parties can agree.

Warranty and class Two distinct types of survey are encountered in the temporary phases of an offshore oil and gas construction project: warranty and classification (‘class’).

Assured parties are obliged to appoint a marine warranty surveyor to perform warranty work whose scope is negotiated with the lead insurance underwriter. In broad terms, a marine warranty survey involves a technical review, site visits and attendance at key operations to provide an independent, expert view of the risks involved in a project’s marine operations and whether they are workable. The marine warranty surveyor’s responsibility is to the underwriter. The Noble Denton marine assurance services provided by DNV GL set industry guidelines for marine warranties.

Class surveys check that floating bodies and their various parts and equipment are fabricated and maintained to standards for their class. Safety related systems in topsides are included in this. Class surveyors are employed by classification organisations such as DNV GL.

“For some, price is an important factor, but we would encourage clients to consider such issues as wording, coverage, financial rating, claims experience, and handling capabilities when deciding on their insurance partner,” Graham said.

Lobo observed: “Our clients like a good price, but many see insurance buying as a long-term relationship and want to be sure insurers will pay if there is a terrible event.”

Such clients do not want to argue with insurers because of poor relationships caused by assured parties switching providers regularly, or because the insurer lacks the financial strength or rating to back the claim.

“Many clients, particularly larger ones, like to keep us on board and maintain the relationship. Conversely, if there is scope for us to offer inducements for them to maintain their risk management at the highest levels, we would look to do that rather than losing a client,” Lobo said.

The value of a company such as DNV GL working alongside Catlin and its clients to provide marine assurance is in building long-term relationships where everyone wishes to see the highest standards, he added.

22 PERSPECTIVES

OPERATORS RAMP UP LIFE EXTENSIONProlonging the productive life of assets is becoming a whole lot smarter as experience grows

PHOTO SHuTTERSTOCK

LIFE EXTENSION

Life extension of ageing assets is moving firmly up the agenda for oil and gas operators in many regions. Factors driving this include: high oil prices; technology advances; regulatory requirements; updated design standards and knowledge; a need to manage risk and ensure safe operation; an enhanced focus on safety; and changes in reservoirs.

“A significant number of offshore platforms world-over are approaching, or have already exceeded, their original design life,” said Anupam Ghosal, who is DNV GL’s service line area manager for verification, Middle East and India. “DNV GL is helping several operators in the Middle East and India region to address the challenges that ageing brings to offshore structures.” India’s multinational Oil and Natural Gas Corporation (ONGC) provides an example of how the issue can be tackled. It has more than 250 fixed offshore platforms, designed to API-RP-2A guidelines. The oldest was installed in 1976, and most had an original design life of 25 years.

“More than 35% of our offshore platforms have outlived their design lives and many more are approaching it,” said Dinesh Kumar, general manager – head structure, at the Institute of Engineering and Ocean Technology (IEOT), the company’s engineering arm. “However, we still require these to be producing hydrocarbons until 2025 to 2030, 15 to 30 years beyond design life.”

ONGC is therefore pursuing the requalification of platforms that have exceeded a design life of 25 years.

Issues with standardsUsing methods from API-RP-2A for reassessing platforms, ONGC’s IEOT reviewed the structural integrity of its offshore platforms. Some did not meet present day API-RP-2A 21st edition requirements on design level and fatigue.

“This was mainly because of a change in hydrodynamic coefficients over the period of time; additional loading due to risers, clamp-on wells, deck extension and so on; and damage from incidents such as collision and dropped objects,” Kumar explained.

Failure of soil, piles, members and joints were major reasons why structural integrity could not be documented. Other issues included the very low fatigue life of some joints, and the fact that results of fatigue analysis and actual inspection did not match.

ONGC has planned to use section 17 of API-RP-2A 21st edition as its framework for action. This deals with assessment of existing offshore structures. Section 17 allows reduced metocean loading for platforms designed around API-RP-2A 20th or earlier editions, and permits the use of ultimate strength analysis for a given reserve strength ratio.

Platforms not passing design level or ultimate strength analysis need >

Risk-based

inspection

would be a cost-

effective tool

considering the

extended life of

the (offshore)

structures”

Dinesh Kumar, general manager – head structure, IEOT ONGC

“


LIFE EXTENSION

Keeping India’s lights on as energy demand rises is one reason to extend the life of its older oil and gas assets

24 PERSPECTIVES

LIFE EXTENSION

strengthening or mitigation measures such as load reduction. However, API-RP-2A does not explicitly deal with life extension of offshore structures.

ONGC considered what DNV GL could offer to facilitate its platform requalification requirements.

“We had extensive discussions with DNV GL experts in Oslo to firm up the proposal,” Kumar said. “In 2008, it became the first organisation to bring out a standard (N-006 for NPD) on Life extension of offshore structures. The company had carried out extensive studies and had vast experience in the life extension of both fixed and floating structures.”

DNV GL has been contracted by ONGC to assist IEOT in developing a requalification methodology for the life extension of 34 platforms, specific to conditions offshore India. ONGC is now interested in implementing a risk-based inspection (RBI) plan for all its ageing offshore structures in the near future.

RBI analysis quantifies risk in terms of the probability and potential consequences of different degradation modes for overall structural integrity, including fatigue. It also aims to establish an inspection schedule for individual joints, so as to

maintain risk below the acceptable level and at all times throughout the considered service life of a platform. Inspection planning identifies a strategy to ensure that legislative and operator requirements on safety are met, and that inspection efforts are prioritised from an overall risk perspective.

With support from specialists in Norway and Denmark, DNV GL’s team in Mumbai, India, leads and delivers the work on the ONGC project.

Scoping the projectThe project involves developing both a philosophy and a methodology alongside IEOT. This includes the screening and grouping of structures, and the reassessment of platforms; particularly where some structural drawings or soil and pile data are missing.

DNV GL has verified in-place and fatigue analysis; conducted independent in-place and fatigue analysis; identified structures requiring advance analysis, such as non-linear pushover analysis; established the scope and extent for further assessments; carried out advance non-linear pushover analysis for platforms to understand failure mechanisms and to identify potential mitigation measures; and has performed advance analysis for low fatigue joints. DNV GL is also developing

suitable RBI plans including mitigation strategies for those structures whose life is extended for up to 15 to 20 years as applicable. The RBI plan for selected structures will be applicable to all 34 platforms.

What is innovative about these approaches? “For one thing, we have developed a smart methodology that groups structures to minimise duplicate analysis. This reduces the total number of analyses carried out,” said Varadaraj Salian, DNV GL project manager for the ONGC work.

While initial work was carried out on grouping, it became apparent that selected representative structures were failing through joints with a high degree of complexity, Salian explained.

As the project moved ahead, the high degree of complexity of different platforms required a higher number of advanced non-linear analyses. Non-linear advance analysis helps to lower substantial expenditure by eliminating or reducing the need for structural modifications to be made offshore.

“Lack of adequate data availability is another common problem for old assets globally,” Salian said. “Real value is added through developing a procedure for the

Production and consumption charts underline the case for more sophisticated approaches to looking after assets such as this ONGC platform offshore Mumbai

PHOTO ONGCGRAPHIC BIG PARTNERSHIP

Rising vehicle ownership, economic growth and incomes over a decade have elevated consumption of oil and natural gas well beyond production levels

Data source: BP statistical review of world energy 2014m

illio

ns o

f to

nnes

of o

il eq

uiva

lent


LIFE EXTENSION

reassessment of platforms where some structural and pile drawings and/or soil data are unavailable. Additional value comes through implementing this procedure for further studies.”

Another feature of note in the ONGC project is that requalification methodology has been developed and implemented specific to local climatic operating conditions, Salian added.

Approach has wider useONGC is confident that the programme will achieve its aims. “The approach taken with DNV GL will definitely meet the objectives we have envisaged,” Kumar said. “using this approach, we would be able to requalify our platforms up to 2030. RBI would be a cost-effective tool considering the extended life of the structures.”

Despite the tailoring of some elements of the ONGC project to local conditions, the strategy, technologies, systems and processes involved could be applied widely, Kumar added.

“The issue of life extension of offshore structures is being faced by a number of operators in this region. I am sure that the approach adopted in our present project would definitely be a starting point for such platforms.”

Approximately half (47%) of the world’s oil and gas companies are actively planning for far longer asset life spans than before, a survey found earlier this year.¹

This is a particularly pressing issue in the Middle East. “There are nearly 750 offshore fixed platforms and bridges in the region. Out of these, the united Arab Emirates (UAE) alone accounts for about 450 structures, and more than 70% of these are older than 25 years with some beyond 40 years,” said Anupam Ghosal, DNV GL service line area manager for verification in the Middle East and India.

Recent news from the region underlines how the need for life extension is driving real action. Company announcements indicate a growing appetite among operators in the Middle East to find intelligent ways of prolonging the productive life of their oil and gas assets. Ghosal highlights four such developments:

The UAE’s Abu Dhabi Marine Operating Company (ADMA-OPCO),

a major producer of oil and gas offshore Abu Dhabi, has launched various life extension projects. It has initiated structural integrity assessment of offshore facilities; integrity assessment of ageing wells; and plans to upgrade and replace all its ageing pipeline networks by 2030.

Meanwhile, Bunduq Oil Company, Abu Dhabi, has taken up structural integrity assessment and risk-based inspection (RBI) for its ageing offshore facilities.

The Al Khafji Joint Operations (KJO) joint venture organisation in the neutral zone between Kuwait and Saudi Arabia is on course to implement an asset performance management (APM) programme. This is to better manage existing aged facilities, and additional new ones, by enhancing availability, reliability and strategy.

DNV GL is working with RasGas in Qatar to set up a structural integrity management system (SIM) for all the operator’s offshore structures.

MIDDLE EAST TACKLES ASSET INTEGRITY HEAD ON

1 ‘Challenging Climates – The outlook for the oil and gas industry 2014’ can be downloaded at: www.dnvgl.com

26 PERSPECTIVES

TACKLING THE BIG DATA BOTTLENECKA USD17.5 million joint industry-academia project is speeding up information retrieval from complex databases

BIG DATA

INFOGRAPHIC OPTIQUE, BIG PARTNERSHIP

Oil and gas companies face a long-standing industry problem in accessing data. It is one of the challenges of larger, deeper and more remote operations, but now comes with the added complexity of collecting and interpreting a huge surge of real-time, digital information generated by multiple fields and plants.

Over recent years, a range of advanced tools have come to the market to help operators make sense of this so-called ‘Big Data’, in order to understand how to bolster performance across thousands of wells and, in real-time, monitor the condition of advanced equipment. But the technical limitations of today’s computing systems are already struggling to manage the amount of information that some operators are required to handle, sparking a search for smarter ways in which data could, and should, be analysed. Big Data solutions aim to effectively aid decision-making, allowing users to work more effectively by focusing on accurate information and how to use it when required.

Big Data is often characterised and quantified by reference to ‘the three Vs’ – volume, velocity, and variety – a description originally coined by Doug Laney, now research vice president of technology analysts Gartner Research.¹

In explorative drilling, for instance, a company will evaluate an area, drill a well, gather real-time data and input this into its system to inform planning for the next well before drilling it. Companies may re-evaluate fields every week and in many

places, driving the volume of data ever upwards.

A collaborative responseAs companies seek smarter ways to handle the influx of complex data, joint industry projects (JIPs) have begun to explore ways of saving time, money and energy through shared goals.

One such initiative is Optique, a four-year joint industry project between several world-leading academic institutions and industry partners. It exploits recent advances in semantic technologies, in which the meaning of data is explicitly represented as part of the data model. The aim is to develop a software platform to provide end-users with flexible, comprehensive, and timely access to large and complex industrial data sets – in processing petabytes of well data, for example – by making computers use the language users understand and are used to.

University of Oslo (UiO) professor Arild Waaler, who coordinates Optique, initiated the project in 2010 and has received backing from Norwegian oil company Statoil, DNV GL, German engineering group Siemens, and fluid Operations, a German provider of innovative cloud and data management solutions. The EuR13.8 million (uSD17.5m) programme launched in December 2012 with EuR9.7m European union funding.

The Optique team expects its approach to reduce turnaround time for >

Our ambition is to

allow engineers

to independently

navigate, retrieve

and simplify

complicated

data, and reduce

the time it takes

to access what

they need ... to

just a matter of

minutes”

Professor Arild Waaler, coordinator, Optique JIP

“

1 Laney, D: ‘3D Data Management: Controlling data volume, velocity, and variety’; Meta Group (now Gartner) (2001)


BIG DATA

Simple caseMost users cannot write questions (queries) in special ways (structured languages) to access relevant data quickly and in required formats. A ‘simple data access’ model offers a limited range of set questions and information types to pull data from various databases that are equally easy or hard (uniform) to connect to and control.

Optique solutionThe Optique JIP exploits advances in semantic technologies that can explore meaning and context behind words and sentences. The goal is software that allows people to use computer language that they can understand so they can get flexible, comprehensive, and timely access to large, complex industrial data sets.

Complex caseThe complex case is a ‘man-in-the-middle’ approach where users send information needs to IT experts who in turn write more sophisticated queries. This finds the right information and presents it in ways that are useful for the purposes involved, but limited IT staff numbers mean it can take days to weeks for users to get it back.

Source: Optique JIP

Figure 1: Common data access scenarios in enterprise context and the Optique approach

Simple case Complex case Optique solution

Application

Uniform sources Disparate sources Disparate sources

Application

Optique

Limited

Predefined queries

Informal

Information need

Possible mismatch

Specialised query

End user End user End user

IT expert

Query translation

Flexible

Ontology-based queries

Optimised

Translated queries

28 PERSPECTIVES

BIG DATA

information requests from days to minutes, while also advancing to data sets whose size and complexity is beyond the reach of existing technologies.

The big pictureWaaler believes that the majority of current solutions for Big Data focus solely on volume and processing large amounts quickly. The Optique project adds another dimension to the three Vs: complexity.

“Traditional technologies are extremely good at volume, but compromise a lot on variety, velocity and complexity,” he said. “Optique is unique in focusing on all these dimensions simultaneously. It also addresses trustworthiness by showing where data came from and how it has changed, providing transparency for the end user.”

Take the variety aspect for instance: “Statoil has hundreds of terabytes of stratigraphy and seismic interpretation data that needs analysis in large and very complex databases. You cannot do this with only the methods developed for big volumes of data, but it is a main goal for Optique. We focus on variety, velocity and complexity, then consume as much data as we can without compromising too much of the other dimensions.”

Optique aims to test and implement a long-term solution for data access that creates a tool for end users to find data on their own, which they cannot do now.

Waaler explained: “Geologists and engineers know what they need, but the problem is posting a complex query to multiple databases. This is impossible without sending a request to IT experts, a scarce resource. End users must wait for these experts to create complex queries. This may take up to several weeks and considerably delays decision-making.”

Optique plans to provide tools to allow a user to query data without assistance from IT experts, and get the result in minutes, he said. “This will open up new exploratory and interactive ways of working as users get more relevant data sets in shorter time. We see Optique as the central tool for exploring information and returning timely, complete, and accurate results. users can then focus fully on what they are trained in.”

A challenge to industryThe Optique solution has been tried and tested in the laboratory. The next step is to implement it within the industry, and DNV GL has taken on the role of bridge builder between the theoretical and practical worlds. Waaler

said remaining challenges include speeding up the performance of the back end by applying massively parallelised solutions and also tools to ease establishing and maintaining installations of the Optique platform.

In early 2015, the Optique team plans to present current results at a conference in Høvik, Norway. The aim is to recruit interested companies as partners to the project. The vision is that by 2020, Optique methods and technology will be incorporated into mainstream information management products delivered by trusted vendors.

“We will deliver a good concept, but this will not be something that can be delivered to the industry two years from now. I hope that by then we have something so impressive that the industry will want to continue to fund this project. I am optimistic,” Waaler said.

For further details about Optique contact: Tore Hartvigsen, DNV GL project manager [email protected]

Source: 65 responses to TNS Gallup AS survey (2014) of 67 participants in DNV GL-led JIPs

How useful are joint industry projects at ... Should the oil and gas industry be standardising more?

Yes71%

No14%

Don't know15%

Providing a neutral ground where industry players can meet to solve common challenges

Developing standards which ensure transparency and predictability

Encouraging greater industry cooperation

Increasing standardisation enabling improved industry adoption and adaptation

Increasing knowledge and competence (without losing competitive advantage)

Managing/Reducing risk

Increasing safety

Very useful Useful Quite useful Moderately useful Not useful at all Don’t know

34

41

23

27

21

6

11

42

34

41

37

43

45

36

16

20

28

29

29

31

30 8

6

6

5

5

5

% finding JIPs useful

Joint industry projects: What do participants get out of them?


ARCTIC ‘RIGSPRAY’ SIMULATION

Sea spray icing is one of the major challenges for drilling rigs, production platforms and vessels in Arctic conditions, yet understanding of how it is generated is limited to very local metocean conditions and sporadic vessel designs.

This needs addressing as Arctic oil and gas activity grows. Operational capabilities of conventional vessels and offshore structures do not currently meet requirements for Arctic conditions.

DNV GL is initiating a ‘RigSpray’ joint industry project (JIP) to develop a simulation model bridging functional winterisation requirements and real physical conditions for drilling rigs, production platforms and vessels.

It aims to guide the implementation of icing-mitigation measures to deliver safety and cost benefits. Experts from the maritime and oil and gas industries are invited to join.

The first step is to develop software to further understand sea spray icing using mathematical modelling and measurements. This will provide a solid basis for extending local ice estimations to a wider spectrum of metocean and structural conditions.

This in turn will lead to safer and more cost-effective winterisation solutions for drilling rigs, production platforms and vessels operating in cold climate areas where sea spray icing is likely.

Contact: Olga Shipilova, project [email protected]

BLOWOUT PREVENTER MAINTENANCE

Traditional time-based maintenance of blowout preventers (BOPs) has significant financial, logistical and safety implications for drillers and rig owners.

Current regulations in some jurisdictions propose alternatives to time-based maintenance. One example is the Petroleum Safety Authority of Norway which has focused on drilling operators’ maintenance functions, thereby increasing industry understanding of risk-based maintenance. The uS Bureau of Safety and Environmental Enforcement is also drafting new rules for BOPs, aiming to boost their capabilities and increase assurance that they will work in an emergency.

DNV GL has established a JIP to develop a risk-based method for more effective and cost-efficient maintenance. Time-based maintenance can create critical challenges such as unstructured maintenance management, high operational downtime, reduced reliability and complete equipment overhauls. The benefits of risk-based maintenance include increased safety and optimal maintenance planning to reduce costs. The initiative aims to provide a recommended practice or international standard within which appropriate maintenance requirements and methods will be identified.

Several BOP manufacturers, operators, rig owners and shelf state regulators have joined the JIP. Others are still welcome on board. A kick-off meeting with industry partners took place in Norway in September 2014.

Contact: Rui Quadrado, project [email protected]

SMALL-SCALE LNG RELEASES

The oil and gas industry has asked DNV GL to initiate a joint industry project to better understand the consequences of an accidental liquefied natural gas (LNG) release.

In particular, challenges remain regarding development of small scale LNG. Regulators in European countries such as the Netherlands and united Kingdom (uK) are currently working on issuing standards for the safe design, siting, construction and operation of LNG filling stations.

The JIP will contribute to the development of well suited safety standards and guidelines for small-scale LNG bunkering and filling stations. DNV GL has already taken steps towards harmonising LNG bunkering operations by launching a recommended practice (RP-0006) providing guidance on how to do this safely and efficiently.

The JIP will run in collaboration with E&P companies and LNG market stakeholders.

Experiments at DNV GL’s Spadeadam Test Site in the uK will gather data to study and understand LNG behaviour following a system failure.

The programme will also include demonstration tests needed to quantify certain major hazards.

Information generated from the tests will be used for quantitative risk assessment.

Contact: Dr Mohammad Ahmad, project [email protected]

JOINT INDuSTRY PROJECTS

Olga Shipilova Rui Quadrado Dr Mohammad Ahmad

30 PERSPECTIVES

REFORM LIFTS MEXICO’S ENERGY PROSPECTSEckhard Hinrichsen analyses the race for oil and gas reserves as the market liberalises

PLATFORM

PHOTOS PEMEX

The Mexican energy industry is at last open to foreign companies. Investment opportunities abound as the important first licensing rounds loom.

The sweeping energy reform bill approved last summer is tipped to transform the country and boost oil production through a ‘Big Bang’ of investment in private sector exploration, development and production of oil and gas assets.

Bidding for fields begins in mid 2015. SENER, Mexico’s energy ministry, has announced that round one will include 169 blocks – comprised of 109 exploration blocks and 60 production blocks – and an additional 14 blocks which will invite bids under joint ventures with Pemex, Mexico’s national oil company. Contracts are expected to be awarded between May and September next year.

Production rise beckonsMexico’s finance secretary Luis Videgaray Caso described it as “a true change in paradigm" for Mexican energy. The government hopes that, by 2025, international entrants and new investment will see oil production catapulted from 2.5 million barrels per day (mmpbd) in 2013 to 3.5mmpbd, a level last seen in 2004.

External analysts see oil production rising if reform is implemented successfully. In a near 75% increase on its previous forecast¹, uS Energy Information Administration (EIA) has predicted that Mexican liquids production (crude oil, gasoline, heating oil, diesel, propane, etc) could stabilise at 2.9mmpbd through 2020 then rise to 3.7mmpbd by 2040.

This is in line with DNV GL expectations that private investment triggered by reform will increase gradually and surpass investments by Pemex within three to four years. There are attractive opportunities on- and offshore, particularly in deepwater, pipelines and mature fields.

Collaboration opens doorsJoint ventures are seen as the most straightforward way to enter Mexico’s newly liberalised door and to get reserves on stream as quickly as possible. For Pemex, they preserve its stake in the action. Pemex CEO Emilio Lozoya has stated already that the company intends to set up 10 different joint ventures with private firms.

While energy reform invites investment, technical information is limited. Pemex currently holds the technical and seismic data. It is being encouraged by government to share its knowledge ahead of the bidding rounds next year.

International

companies

looking to make

inroads quickly

may be best

advised to set

up joint ventures

with Pemex”

Eckhard Hinrichsen, country manager, Mexico, DNV GL

“


PLATFORM

PEMEX FORGES AHEAD AMID REFORM

Mexico’s national oil company Pemex is being assisted by DNV GL to deliver a financial risk assessment of deepwater drilling activities for wells in water depths over 500 metres.

Lakach, Pemex’s first deepwater development, is well underway. The national oil company, whose 76-year monopoly in Mexico effectively ended last year, has four deepwater drilling rigs under contract for exploration and development drilling.

DNV GL is also undertaking pipeline integrity work with Pemex through a consortium.

Based in Mexico for 17 years, DNV GL has been closely involved with clients as debate over the future has given way to a sectoral revolution in the making. The organisation’s eight offices and 170 in-country staff will play their part in the success of the new legislation by continuing to support DNV GL’s partners in safeguarding life, property and the environment.

Supermajors Chevron, Shell, ExxonMobil, BP and Russian company Lukoil, were said to be among those looking to firm up joint venture activity with Pemex as PERSPECTIVES went to print.

Shale boom less sureDespite holding the world’s sixth largest shale reserves, unconventional gas prospects are less defined in Mexico. There are approximately 600 trillion cubic feet of recoverable shale gas in the Burgos and Sabinas Basins, but the country’s energy ministry estimates that uSD100 billion is needed over a decade to develop resources. Among a number of challenges are Mexico’s arid conditions, which lack water for hydraulic fracturing.

Security is a major challenge in the shale areas in northeast Mexico, where there is concern over the dominance of drug cartels and violence.

In addition, there is competition from gas pipeline projects such as the Los Ramones-Frontera EPC pipeline, which will import competitively priced gas 1,200 kilometres (750 miles) from Texas, uS, deep into Mexico’s industrial heartland near Queretaro.

Very little shale activity has taken place so far and good quality geological

information is currently lacking. For new companies, the obstacles are not insurmountable, but cooperation with uS operators would be required to make it viable.

Positive reactionIndustry reaction to reform has been overwhelmingly positive, as the scope is broader than was expected. Although there are complexities to be addressed before it can fully take effect, the energy revolution is expected to improve the long-term outlook for Mexico’s economic growth.

The potential benefits will become clearer once the first few rounds of bidding get into full swing.

Mexico’s president Enrique Peña Nieto sets the seal on sweeping energy reforms

Pemex plans to go deep to boost production

1 EIA International Energy Outlook 2014

www.dnvgl.com

SAFER, SMARTER, GREENER

Documents

DNV GL PERSPECTIVES issue 02-2014