DNV GL Perspectives issue 01-2014

DEPTH OF VISIONStatoil’s Margareth Øvrum on what it takes to create subsea factories of the future

ENHANCED OILRECOVERYGEARS UP

PERSPECTIVESOil and gas industry insight Issue 01 | 2014www.dnvgl.com

SAFER, SMARTER, GREENER

ALSO INSIDE:PATHWAY TO 2050How oil and gas can survive and thrive in a low carbon era of high energy demand

REGULATIONIt pays for operators not to be limited by some jurisdictions’ prescriptive rules

2 PERSPECTIVES ISSuE 01 | 2014 | PERSPECTIVES 3

president for technology, Margareth Øvrum, explains her company’s ambitions to deploy the world’s first fully-functioning process plant on the seabed by 2020.

Getting the most out of mature oil and gas fields has become a strategic priority for many operators too. Raoul Restucci, managing director of Petroleum Development Oman (PDO), and DNV GL’s Moss Daemi, discuss how enhanced oil recovery techniques are increasingly being applied in the Middle East. As the shale gas revolution continues in the united States, and peak oil production looms for the country in 2019, DNV GL’s Lars Sørum discusses whether independent verification is the answer to regulatory change in the unconventional market. Neil Thompson and John Beavers from our uS operations also give their views, as the country deals with an ageing pipeline infrastructure and demand for greater network capacity.

As industry players navigate this evolving energy landscape, DNV GL works with them to develop new technologies, industry standards and best practices. Dr Patrick O’Brien, chief executive officer of Industry Technology Facilitator (ITF), tells us why he believes collaboration is key to industry progress, and how the sector should focus on making joint industry projects deliver better results in the future.

I hope that you find each of the perspectives within this magazine useful.

Elisabeth TørstadCEO, DNV GL – Oil & Gas

Welcome to the first edition of PERSPECTIVES, a new magazine from DNV GL offering insights from our people, customers and industry colleagues on key issues affecting the oil and gas industry. I am delighted to introduce this first issue following DNV and GL Noble Denton joining forces in September last year.

2014 is a special year for us. It is Year One of DNV GL operating as a merged entity with our vision of ‘a global impact for a safe and sustainable future’, but it also marks 150 years of safeguarding life, property and the environment together with our customers. By combining two highly respected companies with parallel histories, DNV GL can now provide an even broader view of the industries in which we operate, helping our customers to make the right choices and decisions for their businesses, the lives they touch and the communities in which they operate.

The oil and gas sector is venturing into a less predictable landscape. The biggest uncertainties are oil and gas prices, and a less predictable supply picture. Coupled with a shorter investment horizon, building a sustainable long-term reserves portfolio has become more challenging.

The articles in this edition aim to discuss a variety of opportunities and challenges affecting an industry that faces a ‘new normal’. DNV GL’s Etienne Romsom provides us with his view on the long-term direction that the industry needs to take to achieve safer and more sustainable operations by 2050. And, as the sector goes deeper to access new offshore reserves, Statoil’s executive vice

4 News The latest updates from DNV GL 6 Safety and sustainabilityTransparency and collaboration are key to DNV GL’s vision of where oil and gas needs to be by 2050

10 Subsea and floating productionMargareth Øvrum says standardisation and fast tracking are vital to Statoil’s subsea factory ambitions

14 Process safetyWhat has the industry learned from incidents such as Macondo, and what more is needed on safety?

16 Enhanced oil recoveryCover story: Petroleum Development Oman’s managing director Raoul Restucci outlines his company’s EOR strategy. We also analyse the future of EOR technologies in the Middle East as Kuwait, Saudi Arabia and Abu Dhabi ponder how to recover higher percentages of oil reserves

CONTENTS

CONTENTS WELCOME

The biggest

uncertainties

are oil and gas

prices and a less

predictable supply

picture. Coupled

with a shorter

investment

horizon, building a

sustainable long-

term reserves

portfolio has

become more

challenging”

“

SEEING THE BIGGERPICTURE

22 UnconventionalsIndependent verification could resolve arguments over regulation of hydraulic fracturing

24 PipelinesPrescriptive regulation is posing a challenge as the uS expands its ageing pipeline infrastructure

26 TechnologyJoint R&D is important but technology deployment could improve, says ITF’s Dr Patrick O’Brien

30 PlatformThe switch from capex to opex in Australia is a huge challenge for industry leaders

PERSPECTIVES 01.2014 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 Coveney, Joyce Dalgarno, Elinor Turander

DESIGN AND LAYOUTThe BIG [email protected]

COVER PHOTOSolar enhanced EOR, Oman.© GlassPoint

© DNV GL AS 2014

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.

© DNV GL

DNV GL headquarters, Høvik, Norway

©iStock.com/acincin


Marianne Hauso, DNV GL regional manager, Norway

WINNER AT GLOBAL RISK AWARDS

DNV GL has been awarded Risk Management Consultancy of the Year, winning the accolade at the Institute of Risk Management’s (IRM) prestigious Global Risk Awards.

Judged by leading international risk management practitioners and academics, the awards are the pinnacle of achievement for risk professionals and organisations.

DNV GL was highly commended for its diverse services across industries such as energy, oil and gas, petrochemicals, aviation and healthcare. Many of its current strategic research programmes received extremely positive recognition. Globally, these include: researching Arctic risks for oil and gas exploration and production; managing future energy supply; and research to promote patient safety.

IRM chief executive Jeremy Harrison said: “The company has shown itself to be creative and innovative in the way it goes about delivering its business to customers.”

Praised by the judges for the excellence of its approach across a range of industries, DNV GL was commended for showing creativity, innovation and a customer-focused approach to finding the right solution. The company also won praise from the Eu parliament, clients and various other stakeholders.

Hari Vamadevan, DNV GL’s regional manager for the uK and Southern Africa, said: “We are extremely grateful to be recognised by IRM for our contribution to the risk management industry over the past year, and are delighted to have been selected as the winner in our category. Through our strong relationships with customers and risk professionals, we have built a strong and sustainable business with a reputation for quality and integrity. Risk management is an increasingly apparent area within the industry and it is an honour to have won.”

ApAchE cONTRAcT fOR vERIfIcATION SERvIcES

A new contract will see DNV GL conduct operations and project verification for all Apache’s North Sea assets: Beryl A & B and Forties A, B, C, D & E. It has a primary term of three years plus two one-year extension options.

DNV GL has had a long history on the Beryl A & B installations, which have been operated by Apache since January 2012, delivering both the safety case and the former certificate of fitness regimes.

With the new contract in place, it will offer a range of verification services to Apache, including risk-based verification with the ultimate aim to ensure that field developments are designed, constructed and installed in accordance with project objectives.

Mark Richardson, projects group manager with Apache North Sea said: “Safety, compliance and production in that order, are the priorities for the delivery of operations and projects in Apache North Sea. Having the right verification body to work with is key to making our activities a success, and we look forward to working with the business.”

NEWS

© Apache Corporation

Beryl Bravo platform

NORWEGIAN ExpANSION DNV GL’s Oil & Gas head office in Norway has relocated from Høvik to Stavanger to be even closer to customers.

Local delivery capacity will be expanded in Stavanger and Bergen and operations will continue in Høvik, Sandefjord, Trondheim and Harstad. More than 800 staff work across Norway and there are plans to further increase head count this year. The Stavanger office delivers services across development phases including exploration, development, operation and decommissioning.

Regional manager Marianne Hauso said strengthening the footprint in west coast Norway is timely to meet growing demands. “The oil and gas industry is facing rapid changes, increasing costs and growing public scrutiny on its safety and environmental performance,” she said. “Since the merger of DNV and GL, we have even more experts holding broad insight in all technical areas, which is critical in helping our customers have safe, reliable and efficient projects and operations.”

© DNV GL

NEWS

RIG REfIT IS fIRST Of ITS KIND IN ThE MIDDLE EAST

DNV GL has played a pivotal role in a massive technical undertaking in the Middle East, assisting in the first ever offshore removal of a jack-up drilling rig for an onshore refit.

MOS Frontier, a three-legged Type MLT116C multi-purpose jack-up rig, is capable of operating in water depths of 300 feet and will be converted into an accommodation support vessel for up to 290 personnel. It will also have a new helideck, lifeboats and platforms fitted.

The contract from Millennium Offshore Services (MOS) involves renewal of the hull and leg steel, electrical works and document control, as well as monitoring quality and safety, and witnessing commissioning and handover.

Completion is expected in June 2014.© Millennium Oilfield Services

The laboratory located at Gul Circle, was officially opened by Norway’s Foreign Minister HE Børge Brende and DNV GL Group executive vice president Remi Eriksen.

The facility demonstrates the company’s continued commitment to be an integral part of Singapore’s growing marine and offshore cluster.

Structured in four service areas, each possessing specific disciplinary capabilities and complementary competencies, the new laboratory will be able to undertake a broad range of services – from microstructure to mega structure and from laboratory testing to field services.

“The new laboratory will operate in premises three times bigger than before,” said Eriksen. “It is equipped with state-of-the-art facilities and higher performance machinery, greatly enhancing our ability to deliver high-end services so that our customers can meet increasing challenges.”

DNV GL Group executive vice president Remi Eriksen and Norway’s Foreign Minister HE Børge Brende open the Group’s expanded laboratory in Singapore

NEW SINGApORE LAB IS TREBLED IN SIzE

© DNV GL


SAFETY AND SuSTAINABILITY SAFETY AND SuSTAINABILITY

TEXT ROBERT STOKESPHOTO DNV GL/NINA RANGOY

Meeting growing energy demand while trying to avoid contributing to irreversible climate change is the main challenge for the global oil and gas industry.

A rising world population will need more than 50% more energy annually by 2050. Continuing on the current path of consuming fossil fuels will cause global warming to exceed 2°C.

Aware of the push and pull between growth in demand and climate change, DNV GL is developing its own vision of where oil and gas needs to go by 2050. Why? “The sustainability issue aligns closely with our company purpose to safeguard life, property and environment,” said Etienne Romsom.

“Our purpose, experience and technical expertise give us cause to express ourselves on the issues, and to suggest a roadmap for the oil and gas industry with some of the breakthroughs that are needed.

“We are working closely with a range of companies keen to develop and implement best practices and we contribute through our own Recommended Practices, Standards and research. We are not a voice for the oil and gas industry, non-governmental organisations (NGOs) or governments. We approach these issues from an independent perspective.”

DNV GL’s report ‘A safe and sustainable future – enabling the transition’ is a starting point to develop this vision. It includes targets that address the distrust that often exists between oil and gas companies, NGOs and the general public, and suggests areas that need improving.

Why 2050? “We wanted to think far enough ahead that our vision would not be constrained by current realities. We also identify the key challenges that need to be overcome to realise our vision,” Romsom said.

“Most gas projects last up to 40 years for full lifecycle, so we need to consider a 2050 perspective in solving some of the bigger changes. It shouldn’t take until 2050 to implement though!”

Far from being “pie in the sky”, it is about describing a world that is “not just possible but desirable” and asking what needs to happen to bring it about, he stressed. “It’s not just about the destination, it’s about the journey. It is about creating a roadmap of what needs to change if we are to reach the destination we aspire to.”

Transparency and collaboration emerged as “probably the most fundamental and important change that is needed”, Romsom said. “The Macondo accident underlines how the reputational and financial consequences of a major incident can humble even the largest company, and it also had substantial implications for the entire industry,” he pointed out.

On companies’ historic preference to develop proprietary technology to gain competitive edge, he said: “Technology development is critical, but intellectual property (IP) is much less a commercial differentiator than it used to be. In the future, differentiation will come from abilities to attract the best human talent and to obtain the trust of the public for companies’ activities.”

Encouragingly, there are examples that demonstrate increased collaboration and openness. Romsom cited his recent experience at the IHS Energy CERAWeek in Houston, USA. The event saw an exchange of views between Marvin E Odum, president of Shell Oil Company and director of its upstream Americas business, Colorado’s governor John Hickenlooper, and Fred Krupp, president of the Environmental Defense Fund, an NGO. >

In the future,

differentiation

will come from

abilities to attract

the best human

talent and to

obtain the trust

of the public

for companies’

activities”

Etienne Romsom, strategy and business development director, DNV GL

“

MAPPING A PATHWAY TO 2050

Transparency and collaboration can help the oil and gas industry adapt to a low carbon future, says Etienne Romsom


“Here was an NGO that based its arguments on rational thought, data and analysis to challenge international oil companies (IOCs) to do the right thing. They were working together, almost as a multi-sector partnership, and recognised that it was the only way to make change, rather than shouting from the rooftops,” Romsom said.

The lesson, he suggested, is that those wanting change would do better to challenge IOCs based on data and facts. “World Wildlife Fund works with IOCs in a similar challenging but constructive manner, for example.”

Instances of collaboration within the industry are increasing. Marine Well Containment Company (MWCC) 1, 2 was created by a number of companies post-Macondo to devise and implement emergency responses to subsea oil leaks. “It’s a good example of companies pooling expertise and resources in a dedicated vehicle acting on behalf of all the partners and able to respond to their needs with the best possible technology, equipment and people,” Romsom explained.

An example of where collaboration could have been beneficial is Queensland Australia (see page 30), where three large LNG projects have been developed at the same time but independently 3. “If they had been able to overcome their hurdles for cooperation, they could have achieved a similar performance from the same infrastructure by paying for only two LNG plants

instead of three. One reason for the cost pressure in oil and gas is that companies are not cooperating enough,” Romsom suggested.

If companies are finding it harder to compete through IP, what can they compete on? “Performance,” Romsom replied, “but what do you measure and report when the public does not trust oil and gas companies to tell the truth about the level of spills or other information?”

The key to making performance a differentiator is openness, he argues. “Many companies have delivered on this for years already, both to enhance their own performance and to protect themselves by showing that even when things do go wrong, they act and respond through the best possible practice.” Still, not all industry players adhere to the same level of openness.

In DNV GL’s report, oil and gas companies incorporate the ‘true cost’ of their activities in their pricing and decision-making in a full lifecycle perspective. Environmental and social impacts appear in corporate reports and on corporate balance sheets. This plays an integral part in oil and gas companies’ investment decisions, stock market evaluations, corporate ratings and project financing. This ‘footprint economics’ approach ensures that the higher environmental cost and societal burden of extracting oil and gas from natural resources are fully accounted for.

SAFETY AND SuSTAINABILITY

“A number of companies is doing this already and some of our customers put a carbon charge in their assessments of their portfolios,” Romsom said. “Projects that have a high carbon footprint rank lower than a similar project with poorer financial forecasts but a lower carbon footprint. It’s partly a hedge against the possibility of a future carbon tax, but it is also about steering portfolios towards lower carbon impact.”

The report has telling observations on the nature, application and levels of carbon taxes. “They will likely make oil and gas more expensive for consumers and give breathing room for renewables to become more competitive,” Romsom said.

His experience is that oil and gas companies recognise the climate challenges but need to see a level playing field where carbon taxes are applied consistently and in a fair, workable and effective manner. “If its implementation is global, I would say that the reputable oil companies will participate and the others will have to join in,” Romsom explained. “If accounting for ‘true costs’ becomes required in financial statements, in annual reports and in submissions to stock exchanges then companies will be forced to put true cost on their balance sheets and this will then guide their performance.”

Could oil and gas companies ever agree on a global plan to tackle climate change? “We’re all in this together,”

SAFETY AND SuSTAINABILITY

Romsom said. “Most oil and gas companies accept the outcome of the major studies on climate change. They are not in denial. I think we need a roadmap that gets us out of the spin, and that is exactly what this vision is about.”

So far, consumers have not challenged oil companies by voting with their feet consistently and widely. That could change quickly if increased transparency allows consumers to experience directly, for example through product labelling, the true costs of the goods they are buying. Romsom concludes that the roadmap towards a safe and sustainable future requires all global citizens to walk a tight-rope together by carefully balancing economic, environmental and societal needs. The bottom line of our actions affects the balance of us all to stay on track.

1: Marine Well Containment Company, Massey M, Offshore Technology Conference, Houston, US, 2011 2: ‘MWCC and Wood Group PSN form uS offshore reserve response team’, Scandinavian Oil & Gas Magazine, March 20133: Australia Pacific LNG (partners Origin, ConocoPhillips, Sinopec); Queensland Curtis LNG (BG); and Gladstone LNG (partners Santos, Petronas, Total, Kogas)

Download the full report at:www.dnvgl.com/oilandgasfuture

© DNV GL


SuBSEA AND FLOATING PRODuCTION

With responsibility for developing efficient projects, and research and innovation, Margareth Øvrum, EVP for technology, projects and drilling at Statoil, has a clear view of the future for the international energy company’s approach to subsea.

While new technology is important, the company is also set on widening the use of technology and achieving standardisation faster. Øvrum said: “There is no contradiction between developing new technology on the one hand, and standardising technologies on the other. Multi-lateral wells on Troll (a gas field offshore Norway) are among our more complex wells, but they are the most efficient because we repeat the same process over and over. We work hard at standardisation and we can see that the company is getting better and better at delivering on standardisation.” Half of Statoil’s current production comes from more than 500 subsea wells and the

SuBSEA AND FLOATING PRODuCTION

© Øyvind Hagen/Statoil

Statoil’s Tyrihans oil and gas field is an entirely subsea solution tied back to installations and infrastructure in its Kristin and Åsgard fields

Åsgard subsea installation

PHOTOS GEIR OTTO JOHANSEN/STATOIL, ØYVIND HAGEN/STATOILTEXT CATHRINE TORPPHOTO HARALD PETTERSEN/STATOIL

© Geir Otto Johansen/Statoil

STANDARDISATION IS THE NEW INNOVATION

Through innovation and collaboration, Statoil aims to develop the elements

for a subsea factory by 2020.In a wide-ranging interview with

PERSPECTIVES, Margareth Øvrum, executive vice president, explains how

standardisation and fast tracking are vital to the process

company has an ambitious target: to deploy the oil and gas industry’s first complete subsea factory – a fully functioning process plant on the seafloor – by the end of the decade.

There are a number of drivers of Statoil’s subsea commitment, Øvrum explained.

“Cost is one of them. For example, we would not have been able to develop the Tyrihans field economically through a platform solution.” Tyrihans is an entirely subsea solution, tied back to installations and infrastructure in the Kristin and Åsgard fields. Another key driver is to exploit the full potential of field reservoirs quickly. The fast-tracking of Statoil’s subsea technologies has reduced time from discovery to production from about five to two years, which significantly reduces costs, Øvrum said.

Subsea also contributes to the life extension of offshore platforms because it allows for tie-ins. In addition, subsea has >


SuBSEA AND FLOATING PRODuCTION SuBSEA AND FLOATING PRODuCTION

deploying proven technology five years down the road.

“It is not by accident that Statoil has many wells and much equipment on the seafloor. It allows us to develop competence faster than the competition, and to use the technology more broadly, for applications other than those originally intended.”

Statoil involves its suppliers in the development of new technology and solutions, as does DNV GL through joint industry projects (see page 29).

“It is a big advantage to work together with the supplier industry as it helps us bring innovation faster to the market. We have complementary skills and the relationship is symbiotic. We would not succeed without our suppliers’ contribution to our innovation activities, and they would not succeed without our willingness to put new solutions to the test,” Øvrum explained. Extensive dealings with academia and a strong relationship with the Norwegian government have also helped, she said.

“The Norwegian authorities have been a driver for more environmentally friendly solutions – there is a fantastic demo laboratory on the Norwegian Continental Shelf (NCS). The globally competitive subsea supply industry

that Norway has today stems from the fact that we have been allowed to test out new solutions. The authorities have been both supportive and demanding, which has driven the industry forward.”

The threat of rising costs Research published by DNV GL1 this year has forecast a period of capital expenditure belt-tightening, as industry operating costs continue to rise. Standardisation and industrialisation are important elements in tackling chronic rising costs, according to Øvrum.

“We tend to make things complex,” she said. “There are more regulations than ever before and we ask for more documentation, which drives up engineering hours. Statoil itself has comprehensive technical requirements. The supply chain has things to improve on, as do we. And there is certainly potential to improve how we manage the interfaces between all parties as well.

“We are working in more remote areas and in deeper waters than before. An increase in cost is to be expected, but we have to turn this trend around. If we don’t, the subsea industry will be priced out of the game.”

1: Challenging Climates: The outlook for the oil and gas industry in 2014, DNV GL

PHOTOS ØYVIND HAGEN/STATOILILLUSTRATION ANNE-SOLFRID WALLØE/STATOIL

improved energy efficiency and enabled field developments that could not otherwise have been achieved.

“When fields are in deeper and colder waters, with more complex reservoirs in more remote areas, subsea is often the only solution,” Øvrum said. Snøhvit in the Barents Sea is one example of how subsea can solve issues that surface installations cannot. Statoil needed an installation invisible from shore and that allowed fishing boats to trawl unhindered.

“There are health, safety and environmental benefits too,” she added. “People-free operations lead to no health risks. A small gas leakage is a lot less dangerous on the seabed than on the topside where you can get an explosive mix. When I was a platform manager (on Gullfaks) the thing in the front of my mind was to avoid gas leaks! Subsea is also positive for climate change as energy efficiency increases.

“Subsea installations reduce maintenance and risk, and weather is not an issue either. As long as you have stringent inspection and asset integrity programmes in place – in addition to constantly monitoring critical parameters such as corrosion – you are unlikely to see any issues. We have developed 520 subsea wells and have not really experienced any problems.”

must separate out more water from oil and gas than today, and you need seafloor storage.

“All of this is achievable, but you need to prove the technology. We cannot test out a number of new components in one go, so we need to take a stepwise approach. We also need our partners at the different fields to be willing to test out new technologies. I would not call this a hurdle, but it is important to obtain.

“We have a very structured roadmap for what elements we need to develop stepwise today to be able to achieve different types of subsea factories in 2020 and beyond. Subsea factories are taking the technology further and further for each field development. Ultimately, we will be able to develop fields under ice; but an Arctic subsea factory will take much longer than 2020 to achieve.”

Cooperating for successThe history of innovation has many examples of trailblazers that took the risks and cost of being first movers or adopters, but Statoil sees the advantages.

Øvrum said: “The number one advantage is that it gives broader and deeper competence. You gain much more being part of the development of new technology and implementing the first tests, rather than just

Journey to 2020Øvrum explains that Statoil will need to take a phased approach to creating a fully-functional subsea factory by the end of the decade.

“You cannot achieve the ultimate solution in one step. We knew that to achieve subsea compression we needed to develop a number of different elements and we did so over a 10- to 15-year period,” she said. Statoil’s first subsea installations were in 1986 at Gullfaks. It now has subsea compressors on Gullfaks and Åsgard. “I often describe the latter as a paradigm shift,” Øvrum said.

Even with long-term experience in developing subsea solutions, Statoil’s goal to create a complete subsea factory by 2020 is nevertheless ambitious. Less complex is the brownfield factory where a compressor is tied to an existing platform. “Then you can go a bit further afield, where you gather subsea templates into a hub that is also on the seabed, rather than on the topside of a platform,” Øvrum explained.

“If you go even further offshore, then you need technology to transport oil and gas over much longer distances than we operate today. Electrical power is also an issue. Longer distances require high voltage electrical supply, and to operate a subsea factory, you

We have developed

520 subsea wells

and have not really

experienced any

problems”

Margareth Øvrum, EVP, Statoil

“

© Anne-Solfrid Walløe/Statoil

Åsgard module in transit Concept for a future subsea compression station in Ormen Lange gas field

© Øyvind Hagen/Statoil

Åsgard subsea compression template

© Photo Øyvind Hagen/Statoil


Offshore oil and gas activities are not, by nature, inherently safe. They involve handling large amounts of pressurised hydrocarbons and other produced fluids and gases. The industry has been improving its process safety performance ever since the Piper Alpha platform incident, in which 167 men died in 1988, but it still has far to go in effectively managing major hazard risks.

Many elements behind the fire, fatalities and massive oil spill from the Macondo field in the Gulf of Mexico in 2010 had been seen before. Decision-making for Transocean’s Deepwater Horizon rig was excessively compartmentalised while drilling the Macondo well. Individuals made critical decisions without fully appreciating how essential these choices were for well integrity and worker safety. During the immediate post-blowout response, many rig systems and processes failed to respond correctly as the incident escalated.

DNV GL believes the industry can still learn much from Macondo. There have been too many major hazard incidents over the last 25 years: Macondo, Montara and Piper Alpha offshore, and Texas City onshore. Lessons are not being embedded into a risk management culture as much as we would like. Decisions needed for long-term management of risks are often replaced by shorter-term decisions on profitability.

The industry has done well to improve occupational safety performance. This contrasts with a lower profile for, and reporting of, process safety issues. Compared with

occupational safety, understanding of process safety differs within companies.

Operations and maintenance people dealing regularly with incidents understand them well and know the importance of barriers to prevent them. But the people who routinely make decisions on investments in training and competence have less experience about contributors to major hazard issues. When we talk to senior management about the potential for, or the impact of, a major hazard event such as fire, blowout or gas explosion, they have not all had that experience. This makes it harder for them to picture and understand the situation.

Safety culture starts in the boardroom. Companies that pioneer in this area show greater board level leadership on major hazard issues, which is to be commended. Many oil and gas companies now send senior management teams for hazard awareness training at DNV GL’s Spadeadam Test Site to see, hear, and feel the potential impact of a major incident. We routinely work with our customers to increase understanding of key levers for success in improving process safety performance.

Regulatory responses to process safety vary globally. North Sea nations such as the uK, Norway, Denmark and the Netherlands deal with operations in relatively harsh environments. They have a good understanding of process safety and have been much quicker to react to lessons from Piper Alpha. Consequently, a risk-based approach to legislation characterises the North Sea Basin, and is seen

REVISITING OIL AND GAS RISKThe Macondo incident has transformed risk management in the offshore arena, but there is still far to go, says DNV GL’s Graham Bennett

PROCESS SAFETY

TEXT GRAHAM BENNETTPHOTOS DNV GL, MAYuMI TERAO

today as a global best practice.

Australia adopted a risk-based approach several years ago. It has worked well. The uS regime, for reasons including the legislative environment, has been more focused on prescriptive rules and legislation.

Prescriptive regimes are relatively easy to implement and monitor, but less effective at preventing new types of accidents that may happen in the future and are not anticipated by existing rules.

The risk-based approach, which has encouraged many operators to go further than local regulations require, has reduced risks while controlling costs. Some countries in Asia Pacific, Africa and the Middle East are yet to develop this approach. They are still formulating regulatory regimes as their hydrocarbon industries develop. However, major operators that have moved into these areas have introduced best practices from the North Sea.

We believe that the most effective offshore safety regime deploys performance-based regulation requiring major hazard reports, including risk assessments and independent verification, and is supplemented by required or recommended specific prescriptive regulation for selected areas. This view is supported by the new European Union Offshore Safety Directive (Directive 2013/30/EU).

Graham Bennett is DNV GL’s VP and business development manager for UK and Southern Africa.

PROCESS SAFETY

IMPROVING WELL CONTROL

The Macondo incident has cast a spotlight on well control standards and the need for more consistency in training. The industry has responded, but one influential voice thinks attitudes to training still need to change.

The International Well Control Forum (IWCF) recently introduced new training standards to improve well competency, and more are to follow. “But for these to have the desired effect there needs to be a behavioural culture shift,” said David Price, CEO. “ultimately, we want to move well training from a system where a candidate turns up on the day, sits a test and is handed a licence towards one with much more continual learning.”

IWCF has meanwhile stepped up its independent audits of the 210 global training providers it has accredited. It conducts one audit weekly, using qualified auditors to examine criteria including facilities, equipment, human resources, lesson observations, practical assessments and management systems.

“If needed, we issue improvement notices and return to the centre to focus on areas of concern. In the most severe cases, we have removed accreditation from centres,” Price explained. Spotchecks supplement planned audits when IWCF receives a complaint or has concerns about a particular training centre.

© Mayumi Terao

Management teams attend DNV GL’s Spadeadam Test Site to experience the potential impact of incidents such as this spindle valve release

© DNV GL


Oman’s portfolio of mature assets and complex oil and gas reservoirs in some of the world’s oldest, hardest rocks, means enhanced oil recovery (EOR) is vital to maximising the economic recovery of its reserves.

Petroleum Development Oman (PDO), which accounts for more than 70% of the Sultanate’s oil production and nearly all of its natural gas supply, says improved oil recovery technologies such as primary depletion and water injection add up to 25% to the recoverable fraction of its oil.

“This is simply too low and we are making a big effort to increase it substantially through enhanced oil recovery technologies,” said Raoul Restucci, managing director of PDO. “Our EOR team aspires to double PDO’s overall recoverable oil volume fraction to above 50%.”

In 2014, EOR will account for 11% of PDO’s production, but this is expected to triple to 33% by 2023. It is currently executing four EOR projects, and designing, engineering or testing a further 12 technologies covering the full spectrum of thermal, chemical and miscible recovery methods. A further six projects are under concept review.

Extensive analysis of PDO’s portfolio of fields has revealed substantial volumes of oil that can still be recovered through EOR, Restucci said.

“To turn this into reality, current EOR efforts with respect to research and development, field and pilot testing, and implementation of successful technologies will continue with the ultimate goal of providing all of PDO’s fields with a suitable EOR development.”

We place a

premium on EOR

solutions which

underpin the

robustness of our

long-term surface

and subsurface

development

and infrastructure

plans”

Raoul Restucci, MD, PDO

Thermal processes currently dominate this EOR portfolio, but rely on burning natural gas to produce steam for injection into the reservoir, which heats Oman’s heavy oil and reduces its viscosity.

“More and more projects will require thermal processes, in turn requiring more and more fuel gas,” Restucci warned. “This is unsustainable, especially bearing in mind the value of gas, the pervasive and increasing demand across Oman and the increasing shortfall of regional supply. We will not only have to discover new alternatives to gas, but also build on other EOR mechanisms.”

In one high profile example of innovation, PDO has successfully used solar heat in trials to generate low-cost, energy-efficient steam for thermal EOR at Amal West as an alternative to gas. The technology from the uS’ GlassPoint Solar (pictured front cover) uses mirrors to focus sunlight ontoheat receivers, all located and protectedinside a glasshouse, converting this into heatfor producing steam from water.

‘Solar EOR is likely to play an important role in the mix of EOR technologies (in Oman),’ according to a report from international accountants EY, published in January 2014.

Restucci reckons that proven technologies could help PDO reach an overall recoverable oil volume of around 40%. This figure could be further raised by other technologies under development.

Specific proven technologies included in field development plans (FDPs) – and currently in operation – include steam flooding in Amal and polymer flooding in Marmul. >

EOR AVOIDS STICKY END TO OILOman leads the way in enhanced oil recovery. Raoul Restucci, managing director of Petroleum Development Oman, tells PERSPECTIVES why and how

“

ENHANCED OIL RECOVERY ENHANCED OIL RECOVERY

TEXT ROBERT STOKESPHOTO GETTY IMAGES

© Getty Images


Others are in the process of being matured into FDPs – such as steam flooding in Amin and in Habur.

Restucci stressed that PDO still faces staff and supply chain challenges as EOR is both capital and labour intensive, and needs high technical expertise.

“We must also ensure that the benefits of our EOR strategy are spread across Oman through the supply chain. That means ensuring that key technologies, services, materials and components required for EOR are ‘Omanised’ as much as possible, while ensuring quality and cost competitiveness,” he added.

PDO talks constantly to potential partners who can help it to execute its EOR strategy safely, reliably, efficiently and sustainably. Research and development for each of its EOR technologies is steered and pursued by its team through its partnership with Shell, universities, joint industry ventures and strategic alliances with relevant parties.

The asset integrity challenge posed by the risk of corrosion in EOR projects is substantial. The injectants PDO uses to extract oil are very aggressive and can produce highly corrosive compounds.

“The technical know-how offered by companies such as DNV GL is valuable in helping us to progress, so that we can identify those technologies and techniques which are best suited to our operations,” Restucci said.

“Currently, we have a contract with DNV GL, and the company has helped us on a number of important projects such as integrity assessments of all our gas facilities. It has also worked on assessing and providing solutions for Duplex Flow Lines and issues with insulation joints, and has provided competent staff to conduct some corrosion control, monitoring plans, material selection and pipeline integrity works.”

Which EOR solution?“We place a premium on EOR solutions which underpin the robustness of our long-term

surface and subsurface development and infrastructure plans,” Restucci explained.So what might new EOR technologies, or refinements to existing technologies, be needed for?

“Each field has its own characteristics and we are constantly assessing which is the best applicable technique, taking into consideration rock properties and mechanics, viscosity of oil, and the depth, pressure and temperature of the reservoir and so on,” he said.

“It is only by methodical data gathering, analysis and testing that we can decide on the best technology to be deployed in each case. Sometimes, it will be necessary to modify our approach and, on other occasions, to move beyond the boundaries of conventional EOR wisdom.”

In one example, PDO has been running a special chemical test following earlier steam trials in its Habhab ultra-heavy oil field. “This chemical has never been used before in our industry, but we believe it could lead to much increased yields from complex heavy oil and tight reservoirs. Several studies were conducted relating to material selection, environmental management and special chemical handling,” Restucci said.

“PDO experts are also working on several other ‘promising’ and ‘emerging’ EOR technologies,” he added. The promising category comprises technologies not yet ready for application on a full field scale and are tested in field pilots or injectivity trials in the field. Examples include an alkaline surfactant polymer pilot at Marmul and a chemical enhanced waterflood pilot in Lekhwair.

The emerging EOR technologies remain in early phase laboratory testing. These have been evaluated as high-potential additions to the proven and promising ones in terms of cost-effectiveness and efficiency.

“It must be emphasised that extracting residual oil is an expensive process so we are concurrently driving ‘lean’ continuous business improvement practices across all our operations and key processes,” Restucci said.

ENHANCED OIL RECOVERY ENHANCED OIL RECOVERY

Solar EOR is

likely to play an

important role

in the mix of

enhanced

oil recovery

technologies

(in Oman)”

EY, January 2014

“

© Steamtech EOR International

PHOTO STEAMTECH EOR INTERNATIONAL

Portable EOR (bottom right) assists steamflooding trials in Oman’s Amal fields


It is widely agreed that the age of so-called ‘easy oil’ is over as onshore and shallow-water fields deplete across the world. Indeed, it seems that production by international oil companies (IOCs) has already peaked (see table).

Some Middle Eastern national oil companies may also be running out of ‘easy oil’. DNV GL data for Kuwait, Qatar, Saudi Arabia and the uAE shows that between 2000 and 2013 their production grew 33%, yet well numbers grew by 109%: more drilling but less incremental oil.

Results indicate that, to meet target production, these countries will need to increase wells drilled per annum from 1,156 in 2013 to 1,558 in 2020, a rise of 35%. “Enhanced oil recovery (EOR) therefore has a bright future in all Middle Eastern oil producing countries,” said Moss Daemi, director for DNV GL’s oil and gas business area in the Middle East, North Africa and India.

The current high and stable oil price is one major enabler of EOR. “It means our customers can expect a good return from

MIDDLE EAST WAKING UP TO EORSlow to develop in all but Oman, EOR is catching on in the region, says DNV GL’s Moss Daemi

ENHANCED OIL RECOVERY

the heavy investment needed,” said Daemi. “Other drivers include the need to arrest the decline in natural production, maximise recovery of oil and increase the return on existing assets.”

Small wonder that 54% of oil and gas companies worldwide are investing in EOR and similar techniques, according to research commissioned by DNV GL earlier this year1.

While these drivers apply to EOR in general, deployment in the Middle East is

The IOCs are showing oil production declines

Company 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Royal Dutch Shell 2,359 2,379 2,253 2,093 2,030 1,899 1,771 1,680 1,709 1,671 1,633Statoil 1,112 1,132 1,135 1,102 1,058 1,070 1,055 1,043 964 939 966Total 1,589 1,661 1,695 1,621 1,506 1,509 1,456 1,381 1,340 1,226 1,220Eni 921 981 1,034 1,111 1,079 1,020 1,026 1,007 997 845 882BP 2,018 2,121 2,531 2,562 2,475 2,414 2,401 2,535 2,375 2,157 2,055ConocoPhillips 701 953 924 926 1,129 1,032 981 1,041 984 861 871Exxon Mobil 2,496 2,516 2,571 2,523 2,681 2,616 2,405 2,387 2,422 2,312 2,185Chevron 1,897 1,823 1,737 1,701 1,759 1,783 1,676 1,872 1,923 1,849 1,764Petrobras 1,533 1,701 1,661 1,847 1,920 1,918 1,978 1,970 2,004 2,021 2,119Petrochina 2,109 2,119 2,265 2,270 2,276 2,299 2,380 2,311 2,350 2,430 2,504 Source of data: Douglas-Westwood million barrels per day (mbd)

ENHANCED OIL RECOVERY

TEXT ROBERT STOKESPHOTO GLASSPOINT

nuanced by the challenge of production from complex geology, as is the case in Oman.

“Oman is more advanced than a number of other Western countries in applying EOR,” Daemi said.

“Aside from Oman, Gulf Cooperation Council (GCC) states have not been much engaged in EOR historically. They enjoyed high rates of natural production from conventional, lighter oils. Saudi Arabia, for example, has some 250 billion (bn) barrels of conventional oil.

There are signs of change, however. Daemi sees EOR playing a prominent role in addressing three key issues for the Middle East as it plans to meet continued global demand for its oil; complex geology; a drive to access heavier crudes; and the need to prolong production from existing reservoirs. The prize is 970bn barrels of known reserves of heavy and extra-heavy oil, most of it undeveloped.

EOR uses gas injection, chemical injection or thermal recovery to improve the sweep efficiency in the extraction process. “There

is no ‘one-size-fits-all’ EOR solution across the Middle East,” Daemi said. Neither is it easy or quick. “You need to gather a lot of data from the reservoir in a pilot scheme,” he explained. “It takes time to characterise a reservoir to select the most appropriate EOR method. Then it can take between five and 10 years before increased production offsets the additional cost of EOR.”

In Abu Dhabi, a 75-year onshore concession to foreign oil majors finished in January 2014. But a new concession has not yet been awarded as the Emirate ponders how to get commitments from would-be partners for maximum extraction of oil over the next 40 years. It is understood that the government is pressing for commitments of 60% or more oil recovery compared with a global average of around 22% for a typical oilfield.2

While full scale EOR implementation in both Abu Dhabi and Saudi Arabia is some way off, both are looking to carbon dioxide injection techniques to boost recovery, Daemi said.

“The Saudis are looking at gas injection and are very much involved in getting the best data out of their reservoirs so decisions about EOR methods will be easier.”

Kuwait is rebalancing production from high dependence on light oils to include more heavy oils from sandstones in the north of the country. A thermal EOR scheme, a full field steam injection project led by Chevron, is developing in the Wafra field in the Partitioned Neutral Zone between Kuwait and Saudi Arabia. The first phase of steam injection is expected to begin in 2017 to produce 80,000 barrels per day (b/d) with subsequent phases boosting this above 500,000b/d.

As an experienced organisation that has been involved in a number of EOR projects for customers, DNV GL can offer support on the best methods for a particular area and on the best sources of gas for injection. “We can carry out feasibility studies, helping the customer in decision-making for deployment of EOR,” Daemi said.

1: Challenging Climates: The outlook for the oil and gas industry in 2014 can be downloaded at: www.dnvgl.com2: Ivan Sandrea and Rafael Sandrea: GLOBAL OIL RESERVES-1: Recovery factors leave vast target for EOR technologies; Oil and Gas Journal, 11 May 2007

© GlassPoint


Shale oil and gas, hydrocarbons trapped in hard and brittle rock at large depths, are a huge potential source of energy. Yet exploration and production (E&P) by horizontal drilling and hydraulic fracturing – also known as well stimulation – meets widespread opposition based on perceptions of health, safety and environmental risks.

In recent years, a number of operators, industry bodies and technical advisors has produced guidelines for best practice in shale development. They include the International Association of Oil and Gas Producers jointly with the International Petroleum Industry Environmental Conservation Association, the uK Onshore Operators Group, the Center for Sustainable Shale Development in the uS, the Canadian Association of Petroleum Producers, and DNV GL.

DNV GL offers an independent assessment through verification of existing and planned shale gas activities based around its own Recommended Practices and other Standards and requirements selected by customers.In March 2014, it launched the first global third-party verification system for comprehensive coverage of shale operations and risks.

“Independent verification of operators’ practices would have an immediate impact and solve much for governments considering arguments about regulation,” said Lars Sørum, director for unconventional oil and gas, DNV GL.

He advised: “If operators do not want to be bound by prescriptive rules, they must ensure that their activity is not seen to need it. As such, operators need to be able to demonstrate that they can manage and mitigate their risk picture in a sustainable manner.”

BEST PRACTICE FOR SHALE OIL AND GASIndependent verification offers a solution to arguments over regulation of hydraulic fracturing

uNCONVENTIONALS

TEXT ROBERT STOKESPHOTO OLE JØRGEN BRATLAND/STATOIL

To policymakers, he said: “Ask operators to show they are operating in a safe and sustainable way by writing up how they do things and having an independent party verify that. It works successfully in so many industries both offshore and onshore, such as LNG plants and refineries.”

It would, he said, also be in the industry’s best interests. “Hydraulic fracturing has become a symbol of everything that is wrong with hydrocarbon exploration onshore and, in my view, that is a fallacy.”

Shale development carries risks, like any oil and gas exploration and production. “But the risk elements of most concern in shale development are mainly on the surface rather than below ground,” Sørum said. “They are related to transportation, chemicals handling, capturing gas from the wellbore and processing it, water and water management, land use and impact, and other elements.”

The two main risks below ground are: well integrity, basically keeping the water, hydrocarbon and fracturing fluid from the rock formations where it does not belong; and keeping fractures from natural faults or the heel of the lateral.

“Both these elements are perfectly manageable if you use the materials and procedures that you are supposed to, follow best practice, and know what you are doing,” Sørum said. “Campaigns against hydraulic fracturing play on risk elements, though these are manageable through best practice.”

uNCONVENTIONALS

Shale gas regulation should

be as simple as it currently is

for offshore exploration and

production”

Lars Sørum, director, unconventional oil and gas, DNV GL

“

Do operators adhere to best practice though? Sørum replied: “In the uS, the increased probability of something happening is driven by the fact that it is a very marginal, high volume business requiring ever greater efficiency from operators in a depressed and largely unbalanced gas market. This in turn creates pressure to drill more and more wells, more rapidly. There is a danger that without proper oversight and governance, you will run into trouble.”

Operators were supportive when the European Commission decided in January 2014 to abandon previous proposals to regulate shale gas exploration in the European union and issue guidelines instead. Sørum was disappointed by the change of mind. “Shale gas regulation should be as simple as it currently is for offshore exploration and production and for other operations that carry risk onshore – show me your safety case, show me your performance standards, show me your barriers and demonstrate to me that they’re implemented.

“I am confident that serious shale gas developers in Europe will adhere to best practice and implement what DNV GL includes in our new Recommended Practice. As an independent company, we make a difference for operators and regulators alike to assist in establishing safe and sustainable shale operations.”

Download DNV GL’s new Recommended Practice for the risk management of shale gas developments at: www.dnvgl.com

© Ole Jørgen Bratland/Statoil

Drilling for shale gas at Williston, North Dakota, uS DNV GL’s view of shale potential


More than 2.5 million miles of pipelines were accounted for in the uS last year. As the country’s shale industry grows and peak oil production looms in 20191, the government is trying to spur greater network capacity and more sophisticated approaches to pipeline safety.

Despite attempts to streamline the Federal review process for interstate natural gas pipeline permit applications through The Natural Gas Pipeline Permitting Reform Act, new pipelines face increasingly tight rights of way, according to Dr Neil Thompson, vice president of DNV GL’s Pipeline Services Department, North America, in Dublin, Ohio.

“New lines must often run alongside, below, above or across existing pipelines and power lines. But electrical interference from other pipelines and power lines can corrode steel pipes through effects known respectively as stray current and induced alternating current,” he explained.

Other forms of corrosion pose integrity threats to offshore pipelines, such as the large number traversing the Gulf of Mexico.

Most uS pipelines are buried: establishing what is already below ground can be tough with more than 3,000 companies operating pipelines. The ageing of the current pipeline infrastructure also presents a challenge for owners and operators seeking the maximum efficiency

from their assets during a time of increased production.“Many onshore high pressure pipelines are 50 to 60 years old, and some Gulf of Mexico pipes have a five-decade lifespan too. This creates a mammoth job in monitoring them and deciding which to replace or rehabilitate when pipeline integrity is threatened,” Thompson said.

These challenges have caused some oil and gas industry players to question the regulatory approach to risks associated with pipelines in the uS.

“Regulation has been driven by historic service failures,” said Dr John Beavers, director of failure investigation and chief scientist at DNV GL’s Dublin, Ohio facility.

MEETING THE US PIPELINES CHALLENGEAgeing pipelines and rising demand pose questions for operators and regulators

PIPELINES

TEXT ROBERT STOKESILLUSTRATION SSUAPHOTO

One such example is an incident in Carlsbad, New Mexico, in August 2000, which DNV GL’s experts were called upon to investigate. An internally corroded natural gas transmission pipeline ruptured, and the resulting ignition of the escaping gas killed 12 people.

Tighter regulation since has seen the proliferation of in-line inspection tools generating data on pipeline condition to supplement aerial and on-the-ground inspection by trained staff. Yet a concern with uS regulation being based largely on past incidents is that it does not account for constantly-changing conditions surrounding a pipeline.

“urbanisation, soil movement and weather variations all have an impact. Pipeline steels, pipe fabrication methods, coating types, and installation procedures also change. These can all have unintended consequences and may not be accounted for through regulation,” Thompson said.

The uS regulatory approach to developing and maintaining pipelines is largely prescriptive, and government defines the actions required of pipeline operators to manage safety and integrity.

However, more than three-quarters (76%) of the country’s oil and gas professionals surveyed last year for a GL Noble Denton study said they would prefer a goal-based approach to regulation2. This sets clear targets in terms of safety and environmental protection, but allows significant

PIPELINES

freedom in the way in which they are achieved.

Goal-based regulation relies on operators using risk management methods – such as independent verification – rooted in probabilities of events occurring separately or in interlinked ways.

“For pipelines, risk depends on location, so an assessment for predicting future risk must be able to analyse and link up causative factors across locations in a quantitative manner and relate these to failure processes,” Thompson said.

“Greater risk management has come into the uS pipeline industry over the past decade, even if it has been rather qualitative in nature,” Beavers added. “We expect more will be included in uS regulation as time goes by. But there is still no requirement for true third-party verification.”

There is a lot of both legacy and new data from in-line monitoring to inform a quantitative risk management approach. “However, there is a need for better data management to enable better and quicker cost-benefit analysis of which pipelines to rehabilitate and which to replace,” Thompson stressed.

1: The International Energy Outlook 2013, US Energy Information Administration (EIA), July 20132: Reinventing Regulation: The impact of uS reform on the oil and gas industry, GL Noble Denton, May 2013

A new DNV GL tool offers data management for smarter cost saving decisions about pipelines. Multi-Analytic Risk Visualisation (MARV) can acquire data at specified times and from different locations, and models the probability of pipeline failure based on threats to integrity. Some of these include manufacturing and construction defects, weather, earthquakes, corrosion, mechanical damage, sabotage and flawed operation. It can also model the likely environmental and safety consequences of a failure.

Input is mainly from incident databases, time based data and geo-graphic based information, though MARV can interface with a number of data sources.

It displays an easily grasped visualisation with a touch-screen interface allowing users to call up specific locations to show, for example, third party damage risk for that location.

As well as the mean value for a risk, MARV shows the values below or above which confidence in the figures drops below 90%. This allows operators to initiate the right responses, such as gathering more data or taking preventive action.

MARV has been tested on small pipelines with industry partners in China and the Middle East. “We will next do a trial on a larger pipeline and hope to make MARV available in the uS by the end of 2014,” said DNV GL’s Dr Neil Thompson.© Ssuaphoto

© DNV GL

DNV GL’s Ohio laboratory plays a key role in post pipeline-failure response

MARV HELPS DECISIONS


Joint industry projects (JIPs) and initiatives in oil and gas have made a significant contribution to technological progress over decades, but one expert facilitator of the approach strongly believes they can and should deliver much more. “We need to be more strategic and forward thinking to maximise hydrocarbon production in the years ahead, particularly when the industry needs to react to more critical issues,” said Dr Patrick O’Brien, chief executive officer of ITF, the oil and gas industry technology development organisation, which recently launched its 200th JIP.

Formed in 1999, ITF is an oil and gas industry-owned, not-for-profit organisation driving purposeful, strategic and collaborative technology development. Owned by 31 international operating and service companies, it currently has 30 projects running and direct member investment is around GBP16 million (uSD10m).

O’Brien’s comments coincide with growing concern and scepticism about the effectiveness of industry alliances for technology development. Critics urge improvements to the deployment of demand-led technology into the industry to make it more effective and sustainable.

He commented: “It is in everybody’s interest to maximise recovery and secure energy supplies, so we need to think carefully about the optimum make-up of each project. For some, such as those based on data sharing or developing good industry practice, a large number of participants may be essential. For others, too many participants may be a hindrance. These projects may deliver better results with a greater focus by fewer companies with a strong desire to see the particular technology developed quickly and deployed.” Oil and gas companies spend heavily on proprietary research, but joint approaches to major challenges confronting the

COLLABORATION DRIVES SMART SOLUTIONSProprietary and joint R&D can go hand in hand, ITF’s Dr Patrick O’Brien tells PERSPECTIVES

TECHNOLOGY

TEXT ALISON COWIEILLUSTRATION EDMOND YANG

global industry are increasing or remain important, O’Brien said.

Arguably, he added, government has a role to play in encouraging collaboration. ITF has close links with the uK’s Technology Strategy Board. DeepStar, the technology development for deepwater research programme launched in the Gulf of Mexico in 1991, illustrates how operators, industry experts and regulators can collaborate in a shared multi-discipline forum to address technical issues, O’Brien said. Accessing reserves in deep- and ultra deepwater and more extreme, hostile environments, continues to dominate demand for technical innovation and more cost-effective solutions. This is not the whole story though. “There is a range of important issues to be tackled in what might be seen as more mundane developments in shallow waters, and at lower temperature and pressure,” O’Brien said. “Ageing assets, life extension,

TECHNOLOGY

If the industry is to

access remaining

reserves, greater

collaboration is

needed”

Dr Patrick O’Brien, CEO, ITF

“

abandonment and corrosion are areas of concern, as are the costs of exploiting smaller, marginal developments. We need to keep a focus on these.”

Other areas of high current interest include smart field development, and both enhanced and improved oil recovery. ITF and DNV GL are both looking at facilitating collaborative ventures around these issues, and are working closely with industry leaders and developers to investigate new ideas.

It is important to understand when collaboration is a good way to deliver benefits, O’Brien said. “I’m currently asking my members these questions: where is your energy for collaboration? Where are you looking to move things forward and is there a barrier to that? Would you like to share or work with others on this problem? My job is to try and make that happen as a facilitator and maintain a healthy environment for JIPs to deliver industry success.” >

© DNV GL

Researchers see a dazzling future for all manner of hydrocarbon and energy technologies such as this artist’s impression, but the road from concept to deployment is often long and bumpy

DNV GL lab in Høvik


JOINT INDUSTRY PROJECTS

DNV GL reinvests five per cent of its annual revenue into the research and development of new technologies to benefit the wider oil and gas industry as it faces up to new challenges.

As part of this commitment, the company brings together in-house technical experts with industry partners to develop new standards and industry best practice through JIPs.

Following a call for ideas, more than 200 proposals were submitted for new, DNV GL-led JIPs in 2014. This is in addition to 275 proposals for oil and gas service development initiatives. Thirty new JIPs will begin by the end of this year, following a rigorous selection process which has involved regional managers globally.

The projects will vary in scale, complexity and in the number of partner organisations, but each has a common goal: to solve a specific technical need and, where possible, to develop a new standard or technology benefiting the whole industry. Two current JIPs illustrate this approach: one on leak detection, the other on sour gas.

Contact: Hans Bratfos, DNV GL’s global head of R&D and innovation: [email protected]

MISSION pOSSIBLE: LEAK DETEcTION Participants are invited to join 20 companies and regulators taking part in DNV GL’s JIP on offshore leak detection. This issue is receiving particular attention from operators and government authorities, who are looking to reduce environmental impact and address public concern over the potential for future hydrocarbon spills.

The initiative aims to develop a Recommended Practice for designing, implementing and operating offshore leak detection systems. Leak detection sensors are currently patchy, offering limited coverage within a field. The JIP aims to integrate subsea and surface sensors into a complete system, providing required coverage and sensitivity while avoiding frequent false alarms. The project will also investigate design, engineering, commissioning and operation of such systems.

The project team consists of representatives from operators, subsea suppliers and leak detection sensor suppliers, as well as DNV GL’s subsea and environmental risk management experts. Christian Markussen, DNV GL’s business development manager for subsea, is project sponsor.

Contact: [email protected] or project manager: [email protected]

MISSION pOSSIBLE: SOuR GAS Sour gas comprises elevated levels of hydrogen sulphide (H2S), which is toxic, highly corrosive and potentially explosive. From 2020, the technically challenging Bab sour gas field in Abu Dhabi will supply 520 million standard cubic feet per day to the uAE. Given Bab’s close proximity to populous cities, there is no margin for error in dealing with the sour gas challenge.

The existing standards and best practices for handling high H2S concentrations are considered to be inadequate. As a result, DNV GL has initiated a JIP to develop international guidelines and best practices to manage these hazards across both developing and currently operating sour gas fields. The scope of this JIP has been expanded to address asset integrity, as well as process safety aspects.

Initiated in early 2014, the project will run for six to eight months, and several national and international companies have already expressed interest in participating. Koheila Molazemi, DNV GL’s risk management and advisory service line manager in the uAE, is coordinating the JIP.

Contact: [email protected]

TECHNOLOGY TECHNOLOGY

He continued: “There will always be competitive areas of technology development in which our members do not want to collaborate. However, there are also common needs that present barriers to development and offer opportunities for collaborative working – this is where the JIPs can play a very valuable role, leveraging funding and accelerating progress.” That said, collaboration and competition are not either/or choices. They can sometimes work together, he added. “A group of operators might gain by collaboratively funding development of equipment they all need, or service companies might work together to acquire data allowing each to develop its own products competitively,” he said. Industry alliances have proven ability to pool knowledge, expertise and best practice, but must be improved. “We collaborate best in times of crisis, and the industry is going through difficult times at the moment. Sometimes the term does feel overused, but its effectiveness is underestimated. If you can decide when you’re going to compete and when you’re going to

collaborate, be clearer about where there’s energy for collaboration and then put every effort into it succeeding, it can reap rewards,” O’Brien said. He believes that more needs to be done to strengthen the route from early feasibility work through to deployment and commends DNV GL’s commitment to improving the efficiency of the JIP model. “With its extensive technical know-how but without having to focus on day-to-day operational issues, the organisation, like ITF, can apply long-term thinking, a very good platform for JIP success.” ITF has been at the forefront of many significant innovations that attracted widespread industry support. At a cost of GBP1.8m and funded by six operators, the Continuous Circulation System for drilling projects took five years to complete from feasibility study to prototype manufacture, followed by field development, championed by Statoil. As the licensee, it was commercialised by National Oilwell Varco (NOV) and now has more than 2,000 connections in the field by Statoil, ConocoPhillips and Petrobras.

In partnership with Imperial College, London, uK, the Fullwave Gamechanger JIP saw the development of full-wavefield tomography technology, which has pushed forward the boundaries of seismic imaging and hydrocarbon reserve mapping. The Subsea Mudlift JIP, launched in 1996 with 22 participants, led to the development and deployment of new dual gradient drilling technology and to the delivery of Chevron’s purpose-built Santa Ana Drillship in 2012 to offer this technique.

“While we are conscious at ITF that we can do more to improve the JIP model and its practice, we are in no doubt that if the industry is to access remaining reserves, greater collaboration is needed to drive forward game-changing solutions, and we intend to play our part in making that happen,” O’Brien said. Dr Patrick O’Brien is a chartered engineer with close to 30 years’ oil and gas industry experience. He is a Fellow of the Royal Academy of Engineering, an honorary professor at the University of Aberdeen, was a founding director of Subsea UK, and joined ITF in April 2013.

© DNV GL

Research at DNV GL’s Høvik laboratories

Hans Bratfos Christian Markussen Koheila Molazemi


The rapid development of multi-billion dollar liquefied natural gas (LNG) ventures has given rise to huge growth potential in Australia’s hydrocarbon production rates. The transition from mega project capital expenditure (capex) to operating expenditure (opex) in particular will require a whole new mindset and presents some huge challenges for industry leaders to overcome.

There are five major LNG projects currently under development, at an estimated total capital cost of uSD160 billion (AuD149bn). International analysts GBI Research reckon these combined investments will push Australia ahead of Qatar to become the world’s biggest LNG exporter in 2017. A January 2014 report from Lux Research noted that the country looks set to become ‘the next big energy market’ for shale oil and gas, ahead of China. Research by DNV GL identified Australia as a top three investment destination for the oil and gas industry in 2014.1

Looking at the phenomenal LNG export potential and huge economic benefits from mega projects such as

the Gorgon LNG and Ichthys projects offshore Western Australia and the QGC project in Queensland, industry experts agree that this incredible rate of capex will not be sustained for much longer. They say the country must prepare to meet a ‘new normal’ in exploration and production.

Like the North Sea 40 years ago, Australia is now a hotspot for major investment seekers, but the scale and succession of projects is mammoth compared to those undertaken from Aberdeen and Stavanger.

While there may be experience of dealing with capital expenditure of USD20 or 30 million for a standard project, the move from major to mega contracts sings to the tune of uSD20bn or more Down under.

A financial dream come true some may say, but with dreams in the oil and gas industry comes the costly, stark reality of an incredible scope of work, increased technical and logistical problems, and perhaps insurmountable risk.

CAPEX TO OPEX CHALLENGESRichard Palmer analyses a major issue of the moment in Australian oil and gas Richard Palmer, regional manager,

Australia, New Zealand and Papua New Guinea, DNV GL

PLATFORM: AuSTRALIA

TEXT RICHARD PALMERPHOTO CHEVRON, QGC

Consistent and thorough communication during the capex phase of a project is key to success and is a skill the industry needs to improve on; a breakdown in negotiations could price Australia out of the market.

When broaching the transition from capex to opex for some mega projects, fundamental issues around procedures, tools and processes must be in place to support operational assets beyond short-term ambitions. Poor long-term planning halted operations soon after the construction boom in the mining industry in Australia, a setback that should provide a valuable lesson for leaders looking to capitalise on oil and gas.

With this in mind, the industry must act quickly as mega developments gather pace. Several LNG streams are projected to start coming online in 2014, such as BG Group’s QGC project (QCLNG), while Gorgon is expected to start supplying in the first quarter of 2015. However, challenges accompanying the imminent switch from mega project capex to opex may be eased by a reduced number of new projects in the pipeline. This may give the industry’s motivators and innovators valuable time to enhance the performance of projects currently in development, while keeping focused on how to resource future prospects such as the mass expansion of floating LNG technology.

uncertainty over capex is putting pressure on project budgets and schedules, and how Australia handles the transition to opex will have huge ramifications for the industry. However, it need only look at mistakes made during development of the mining industry and the lasting legacy of the North Sea to avoid boom turning to gloom.

1: Challenging Climates: The outlook for the oil and gas industry in 2014 is available to download at: www.dnvgl.com

PLATFORM: AuSTRALIA

The industry must act

quickly as mega developments

gather pace”

Richard Palmer, DNV GL

“

© Chevron

Gorgon LNG project, Queensland

Queensland Curtis LNG (QCLNG) project

THE LNG CAPEX PARTY IS OVER

Annual capex, excluding exploration, on LNG projects probably peaked in 2013 at around AuD55 billion (uSD50.9 billion) and will decline from 2014 onwards as the first few mega LNG projects near completion, economists at ANZ Research predicted in January 2014. The initial stages of the QCLNG and Gorgon projects will likely complete by the end of 2014 and the first half of 2015 respectively. Remaining projects, Prelude excluded, will probably complete by the end of 2016. “If no further LNG developments or expansions are approved, capex in this sector would decline to under AuD5bn by 2017,” ANZ Research estimated. This does not mean, however, that the Australian oil and gas industry as a whole is going to dry up.

© OCG

Documents

DNV GL Perspectives issue 01-2014