InnovOil Issue 52 May 2017

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NEWSBASE

Bringing you the latest innovations in exploration, production and refining Issue 52

LIQUID MARKET

The technologies aiding LNG at sea Pages 13-21

May 2017

NEW KIDS ON THE BLOCK

Can blockchain technologies help oil and gas?

Page 22

THE FUTURE OF FPSOS

INTECSEA unveils the Low-Motion concept Page 6

THE FUTURE OF GAS A SPECIAL REPORT BY ADDLESHAW GODDARD AND NEWSBASE

The dedicated Oil & Gas team at international law firm, Addleshaw Goddard is delighted to have partnered with NewsBase and our clients and contacts in the international gas community to publish the Future of Gas Report, a dedicated report focussing on global gas market trends and the role of natural gas in future energy supply. To be launched in London on 16 May and Aberdeen on 6 June, following the Oil & Gas UK Conference.

LONDON EVENT 16 May 2017 at Addleshaw Goddard, Milton Gate, 60 Chiswell Street, London EC1Y 4AG. Registration from 5pm, ending at 7pm followed by networking drinks.

A panel discussion focussing on the report’s key themes, with confirmed panellists including: ► Anna Nerush - Oil & Gas Partner - Addleshaw Goddard LLP ► Nicola Pitts - Head of Gas Market Change - National Grid ► Mauro Fiorucci - EMEA Director - Opportune LLP ► Mark Simons - Director - Energy Flux Facilitated by Ed Reed - Senior Editor - NewsBase.

ABERDEEN EVENT We are delighted to be sponsoring the Industry Vision session at the Oil & Gas UK conference in Aberdeen on 6 June 2017 after which we will be hosting a bespoke event focussed on the Future of Gas Report.

For more details or to register for either event, please contact: jennifer.ellis@addleshawgoddard.com

addleshawgoddard.com

InnovOil

May 2017

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Inside

Contacts: Media Director Ryan Stevenson ryans@newsbase.com

A note from the Editor

Media Sales

Innovation in low-motion 6

Charles Villiers Email: charlesv@newsbase.com

INTECSEA’s new FPSO concept

Thawing ambitions

Kevin John kevinj@newsbase.com

Russian Arctic plans may be warming up

Editor Andrew Dykes andrewd@newsbase.com NewsBase Limited Centrum House, 108-114 Dundas Street Edinburgh EH3 5DQ

Blockchain – an opportunity for energy producers and consumers?

In many cases, this uncertainty can be explained by an insufficient understanding of how blockchains work.

Essentially, a blockchain is a digital contract permitting an individual party to conduct and bill a transaction (e.g. a sale of electricity) directly (peer-to-peer) with another party. The peer-to-peer concept means that all transactions are stored on a network of computers consisting of the computers of the provider and customer participating in a transaction, as well as of the computers

Phone: +44 (0)131 478 7000 www.newsbase.com www.innovoil.co.uk

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of many other network participants.

Traditional intermediaries, e.g. a bank, are no longer required under this model, as the other participants in the network act as witnesses to each transaction carried out between a provider and a customer, and as such can afterwards also provide confirmation of the details of a transaction, because all relevant information is distributed to the network and stored locally on the computers of all participants.

A provider and a customer agree a transaction

The transaction is combined with other transactions made during the same period to create a data block

Figure 3: The verification process

Individual transactions are combined to form a block.

The data contained in each block is verified using algorithms that only produce the correct hash (e.g. 53l4hfi73rtp2fh73p...) only if the right combination is found.

NEWSBASE

53l4hfi73rtp2fh73p...

53l4hfi73rtp2fh73p...

ction ations in exploration, produ Bringing you the latest innov

The verified block is combined with all other blocks previously verified, thereby creating a (continuously growing) blockchain

The transaction is confirmed to both parties

How does a blockchain work?

™

The new block is added at the end of the continuously growing blockchain. The data stored on each blockchain (across all blocks) is also continuously verified.

and refining May 2017

Issue 52

53l4hfi73rtp2fh73p...

53l4hfi73rtp2fh73p...

53l4hfi73rtp2fh73p...

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LNG @ Sea

13

Carried away

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Bunkering down

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Cooling off

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Pioneering projects

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Ready for no jetty

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Never break the chain

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Thin gold Duke

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Cap-X reductions

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Indian Innovation

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The final frontier

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News in brief

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DSME & DNV’s post-Panamax design

HHI unveils glycol regas system

The data block is stored in the decentralised global network in a tamper-proof manner and thus verified

53l4hfi73rtp2fh73p...

Where a provider and a customer agree to enter into a transaction, they determine the variables of this transaction by specifying the recipient, the sender and the size of the transaction, among other things. All information relating to an individual transaction is then combined with the details of other transactions made during the same period to create a new block of data. This is comparable to sending emails, which are also split into separate data blocks. Blockchains are different in that this process relates to a single standardised transaction.

Each transaction is encrypted and distributed to many individual computers (peer-to-peer), each of which stores the data locally. The members of the network automatically confirm (verify) the transactions stored on the individual computers.

Chart Industries on LNG innovation

Wärtsilä’s “jettyless” LNG concept

How the blockchain can aid oil and gas

Duke University gas sensor

New equipment for Bauge

Shell opens Bangalore technology hub

Using space technology in oil and gas

liquid market

The technologies aiding LNG at sea

k New kids oN the bloc and gas?

help oil Can blockchain technologies

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fPsos the future of otion concept

INTECSEA unveils the Low-M

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Tech Radar

NewsBase Research on LNG marine fuel

Figure 2: The blockchain process

Design: Michael Gill michael@michaelgill.co.uk www.michaelgill.eu

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Contacts 41

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Pages 13-21

NEWSBASE

May 2017

InnovOil

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A note from the Editor When it rains, it pours.

April, known for its spring showers, provided InnovOil with a deluge of oil and gas technology this month. A trip to Oslo and the Subsea Valley (SSV) Conference offered incredible insight into some of the most interesting projects and equipment in the Norwegian and North Seas – more of which we will cover in the coming months.

Our tour included a view of the past and future of Norwegian energy, from the foundation of the country’s “second industrial revolution” laid by Norsk Hydro in 1905, to the innovative subsea and technology companies now building on that legacy. With the support of groups like SSV, the country’s NOC Statoil and the Norwegian government, delegates to the conference seemed optimistic that new oil and gas projects would be measurably smarter, more productive and more costeffective than before.

Neither is this the only opportunity they see. Even though oil and gas remains central to the country’s economy, many of these firms are looking to a more diverse future, applying their solutions to the marine energy, agriculture and research sectors, helping to ensure that technological innovation is sustainable.

This month, however, our attention focuses on technologies driving the world’s LNG market. With LNG supplies having averaged 6.2% growth between 2000 and

2015, and trade having totalled 258 million tonnes in 2016, according to the International Gas Union (IGU), the sector continues to hold considerable opportunities for innovators.

Vessels in particular have seen a flurry of activity, from LNG fuel conversions to loading and transfer technologies. That pool is expanding too: as of January 2017, the global LNG shipping fleet comprised some 439 vessels, including FSRUs and floating storage units.

During 2016, 31 newbuilds sailed out of global shipyards, a 7% increase on the previous year, the IGU notes.

Our in-depth features include a look at DSME and DNV GL’s latest carrier design, Chart Industries’ involvement in innovative marine LNG projects, Wärtsilä’s new floating LNG transfer system and much more.

Elsewhere, we profile the latest FPSO proposed by engineers INTECSEA – a design which, its proponents say, could shave over US$1 billion from field development costs compared with conventional floating production options. We hear more from lead engineer Alaa Mansour inside. In addition, we look to the frontiers of the Russian Arctic and even further to the rise in satellite and orbital technologies which are now helping oil and gas operators across the world.

We are pleased to present the May issue of InnovOil.

Andrew Dykes Editor

NEWSBASE

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InnovOil

May 2017

Poetry in low-motion INTECSEA discusses the design and benefits of its latest range of “low-motion” FPSOs

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NCE the flexible workhorse of the frontier offshore oil and gas industry, floating production, storage and offload (FPSO) vessels have had a quiet 18 months. Forecasts for use and expenditure sank, and order books lay pretty much empty from mid-2015 until the end of 2016, while low prices marred development in the traditional markets of West Africa, Brazil and Australia.

With a relatively stable oil price now perceived to be at hand, green shoots are emerging. But an industry focused on cost reduction is still in need of some bright ideas and innovation to boost efficiency. Enter engineering consultancy INTECSEA, with a new range of so-called “low-motion” (LM) floaters, aimed at reducing both the up-front capex of floating developments, and the opex over the desired charter period.

First announced in November 2016, the range now includes designs for the LM-FPSO, LM-FLNG and LM-Semi variants. Suitable for use in shallow water and all the way to 3,000m and above, the company claims that the LM-FPSO can dramatically alter the economics of remote offshore fields, with harsh operating conditions, delivering savings of between US$500 million and US$1.2 billion per project. For an industry just making it through the doldrums of FIDs, this may be music to operator ears.

Solid concept “The FPSO has the advantage of providing the required storage in the hull and direct offloading to tankers,” explains INTECSEA marine engineering manager and project lead Alaa Mansour. “However, the inherently high dynamic motions of a conventional FPSO make it an unsuitable host for the simpler,

robust, lowest capex and opex riser solutions.”

The key innovation in the company’s new concept is a solid ballast tank (SBT) attached to the floater hull through groups of short tendons. This offers increased stability and reduced motion in wave surge, sway and yaw – less than a third of the motion experienced by a SPAR – and so much so that the company has likened its performance to that of a tension-leg platform (TLP).

Better stability means that the SBT can then be anchored to the seafloor using simpler and less expensive steel catenary risers (SCRs). Traditionally, the high dynamic motions experienced by FPSOs would make SCRs an unfeasible choice in most environments. Moreover, even if a lack of excessive movement could be guaranteed, the vessel would require many, large-diameter SCRs, again pushing up costs.

Likewise, top-tensioned risers (TTRs) provide benefits in allowing direct vertical access (DVA) to production wells and can help improve recovery. But owing to the stroke limitation of qualified tensioner technologies, the use of TTRs requires a floating system with minimal heave response, making them unsuitable for use with existing FPSOs. In dry tree unit (DTU) applications when storage is required, a wellhead platform is typically used alongside an FPSO, adding significant expense to the overall field development cost. Instead, with the LM range, well drilling and completions can be undertaken from the FPSO. The SBT itself contains dedicated compartments for high density material (concrete, slurry or iron ore) to provide inwater weight and maintain tendons in tension for all design conditions. The remaining SBT volume is completely flooded with seawater at its in-place condition, meaning the LM range can still be integrated quayside and then towed out for service installation.

When not in service, the SBT is retracted to the hull and kept in this position through its buoyancy force. Once the platform reaches the desired field position, the SBT is flooded and lowered using two mooring chains at each corner, used temporarily for this purpose.

The tendons are then upended and installed. No coupling or installation derrick NEWSBASE

barge is required for the tendon installation, again reducing costs.

Steady as she goes Back above water, the hull itself has a rectangular cross sectional shape, which enables a straightforward rectangular topside footprint with proper separation between the process and living quarters, while allowing for flexible equipment arrangements.

In addition to savings in design and equipment use, being less sensitive to gravity and weight changes also reduces the risk to the project schedule and operating costs. Rough weather and waves have a far less pronounced effect on process safety, helicopter operability and the working time of the crew on board, all of which helps the operator maintain production and reduce unnecessary downtime.

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Below: LM FP50 Dry tree application Right: Artist’s impression

A steadier topside also helps with product storage. “Due to the high stability offered by the shape of the hull and the attachment of the solid ballast tank at the keel level of the hull, the topside can now be arranged vertically and heavy equipment can be located at the top level accessible by the platform cranes for easy maintenance,” Mansour told InnovOil. “Temperature sensitive equipment can now be elevated high enough above any green water effect on top of the hull.

Large-diameter risers can be adopted and less sloshing is predicted in storage tanks.”

Another hull innovation helps to shed further costs. Most conventional FPSOs also require a turret mooring system – a central bearing assembly that allows the vessel to rotate around the static portion, which is moored to the seabed. Often, a fast disconnection system is used in the event that

the vessel needs to detach quickly from the turret, for example in the event of extreme waves or weather. These are sound safety options, but they add considerable cost to the development.

INTECSEA’s design enables the LM to use a conventional mooring system, eliminating the need for this costlier option even in harsh operating conditions. Although the mooring system must be more robust and more expensive than traditional options, by the company’s reckoning the removal of the turret equates to a US$250 million saving straight off the bat.

Float on Unsurprisingly, INTECSEA is excited over the prospects for the LM range. Its scalability – the company says it could be used at fields producing 2 million bpd and above – could NEWSBASE

see it become an industry-standard blueprint for future oil and gas development, if the industry can be persuaded of its benefits.

In a statement, INTECSEA president Geeta Thakorlal noted: “With the easy oil long gone, operators are increasingly turning to more remote, hostile and often deepwater environments. However, the challenge is the financial viability of these fields. The LM technology is incredibly exciting because it represents a major step forward in improving the economics of these offshore developments.”

Mansour, for one, is equally hopeful.

“Since the early phases of the LM-technology development, INTECSEA has been very keen to engage with subject matter experts from the operators, vendors, fabricators and installers to understand their feedback and address any risks,” he said.

Over the past two years, the group has held a number of open industry meetings to help determine the programme direction. Its most recent was a technology risk assessment workshop in February 2017, which followed the successful completion of a five-week model testing programme performed in collaboration with the Korea Research Institute for Ships and Ocean Engineering (KRISO). So far, Mansour adds, feedback has been “very positive” and no major risks have been identified.

As a result, momentum is building steadily. “DNV GL DNV has completed its review of the design and an Approval in Principle (AiP) certificate is imminent. [This] is the last key milestone in the roadmap towards a project-ready LM-FPSO, and the technology is now ready for deployment.”

And if INTECSEA can deliver the project savings it expects to, the floater market is about to be hit by some big waves. n Contact:

Tel: +1 (0)281 987 0800 Email: info.USA@intecsea.com Web: www.intecsea.com

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Russian Arctic offshore In the long term, Rosneft and other companies working on the northern sea shelf will benefit from higher oil prices and investments in the domestic oilfield service sector, writes Jennifer DeLay

S

O far, Russia’s attempts to launch largescale exploration and development of shallow and deepwater fields on the Arctic Sea shelf have had mixed results.

For example, Gazprom tried several times over a period of 20 years to set up a consortium to exploit Shtokman, a massive natural gas and condensate field in the Barents Sea. But it finally put the scheme on hold in 2012, owing to disagreements with foreign partners and concerns about unfavourable market conditions. Likewise, Rosneft’s first attempt to open up the East Prinovozemelsky (EPNZ) block in the Kara Sea foundered in 2011 when TNK-BP, a Russian-based company, blocked its shareholder BP’s bid to join the project.

Rosneft was eventually able to strike another deal on ENPZ with ExxonMobil, but that was not the end of its troubles in the Arctic. In the first half of 2014, it was one of several Russian companies identified as a target in the Western sanctions regime imposed on Russia for its seizure of Crimea and interference in Ukraine’s political crisis.

Then in the second half of 2014, it was left reeling by the collapse of world oil prices.

The former was a problem because the sanctions restricted Russia’s ability to secure sophisticated equipment and technologies from the US and European firms that are most capable of supporting exploration and production work at remote sites where harsh weather conditions prevail. The latter, meanwhile, undermined the economic rationale of Russia’s Arctic projects by making them unprofitable.

Under those circumstances, Russian companies’ moves to push back the timeline for beginning exploration and production work at Arctic fields were hardly surprising.

Nor was the Russian government’s talk about concentrating on low-cost onshore projects and keeping the Arctic as a reserve for future development.

Lately, though, there have been a few glimmers of hope. Oil prices have recovered somewhat, though they are still far below the levels marked in mid-2014. At the same time, the Russian government is working to build up the capabilities of the domestic oilfield service sector in order to mitigate the country’s dependence on imported equipment and technologies. This report will attempt to determine whether Russia’s Arctic prospects have truly improved as a result of these developments.

Breaking the ice On a superficial level, Russian Arctic operators’ situation resembles that of the NEWSBASE

US unconventional oil sector. Both suffered major setbacks as a result of the oil price crash, and both have sought to make technical and technological advances with the aim of reducing their costs enough to justify further exploration and development.

Likewise, players in both arenas have benefited from OPEC’s decision to reduce crude output with the co-operation of Russia and other producers. That move has helped oil prices move back to around US$50 per barrel since last autumn – less than half the level reported in July 2014, but still significantly above the nadir reached in the first quarter of 2016.

Overall, the price rise has been good news for US unconventional developers. In some basins, current market conditions have made shale operations viable once again. For example, companies working in the Permian Basin, where production costs are around US$35 per barrel, are now turning a profit.

By contrast, problems have persisted in higher-cost basins such as the Bakken shale,

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plans heat up

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The Franz Josef Land archipelago between the Barents and Kara Seas

billion rubles (US$447 million) in order to establish a shipyard and marine service base at Belokamenka, a village in the Murmansk region. The company drew up plans for the facility in order to support Arctic LNG, a scheme that envisions the construction of a second onshore gas liquefaction plant on the Gulf of Ob. But local officials have said that the shipyard will make drilling platforms for use at sites in the western Barents Sea as well as ice-breaking tankers for the Arctic LNG project.

where average production costs are upwards of US$65 per barrel.

Similarly, Rosneft and other companies eyeing Russia’s Arctic Sea shelf are still waiting.

Even though prices have risen, they are still below the break-even level, which Russian Energy Minister Alexander Novak recently estimated at US$70 per barrel or more.

Speaking at the International Arctic Forum in Arkhangelsk on March 29, Novak said that northern projects would not turn a profit unless crude prices moved into the US$70-100 range.

The necessity of invention Rosneft and its cohorts will probably have to wait to reach this milestone, as many industry experts believe that crude prices are not likely to approach US$70 and remain there until about 2019. In the interim, though, Russia has a number of options at its disposal to help make Arctic projects more competitive.

The US unconventional oil sector’s experience would suggest that this can

work. In that region, many companies have undertaken research and development campaigns or have revamped their work plans with the intent of making drilling and other operations less expensive. In many cases, these efforts have succeeded, and as a result, break-even costs have declined over the last two years.

Moscow, for its part, also sees innovation as a means of lightening the burden on the companies that hold offshore Arctic licences.

To this end, it has formulated a policy of import substitution – that is, building up the domestic oilfield service sector with the aim of reducing reliance on foreign equipment and production technologies. It has invested in shipyards and manufacturing facilities and has voiced support for corporate plans to establish onshore service bases for offshore operations.

Russian companies – even privately owned firms – have followed the government’s lead on this front. Novatek, for example, is reportedly prepared to invest more than 25 NEWSBASE

Returns on investment It remains to be seen whether public and private investments into such projects will pay off, especially if the US and Europe take a relaxed attitude toward enforcing the parts of the sanctions regime that limit technology transfers and equipment sales. NewsBase Intelligence (NBI) suspects, though, that Russia cannot replicate the US unconventional sector’s success on this front.

For one thing, offshore projects are inherently more difficult, and the difficulties are compounded by the harsh climate conditions of the Arctic Sea shelf. US operators, by contrast, have been working onshore at sites that do not experience such dire winters.

For another, US producers also had the advantage of access to extensive onshore infrastructure networks. Russia, on the other hand, is still working to develop such networks to serve its northernmost hydrocarbon frontier, and such a scarcity will help keep costs high for Russian Arctic projects for at least another 10 years.

Overall, then, the rise in world crude oil prices and Moscow’s efforts to invest in the domestic oilfield service sector have improved the outlook for Russian Arctic projects. They have not, however, brought the high cost of such initiatives down or shortened the timeline for beginning production.

This is not necessarily an urgent problem in the short term, as the Russian government is still treating the Arctic offshore areas mostly as a reserve for future production. In the long term, though, the investments in oilfield service are likely to generate returns.

That is, once Moscow gives the green light for accelerating development work in the Arctic, Russian companies will benefit from already knowing where to find the ships, drilling platforms and other equipment needed for northern offshore projects. n

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On the radar

What caught our attention outside the world of oil and gas this month

Out of thin air A joint team from the US’ MIT and University of California at Berkeley has developed an intriguing system for drawing water from the air, even at very dry locations.

A number of expensive and power-hungry systems already exist for harvesting water from moist air, such as fog or dew harvesting: these require refrigeration. What sets the latest method apart is that it is completely passive.

According to the team, it is “the first that has potential for widespread use in virtually any location, regardless of humidity levels.”

It uses a passive “foam-like material” that draws moisture into its pores, and is powered entirely by solar heat, with no moving parts.

The foam itself is a metal-organic framework (MOF) and its sponge-like configuration offers a large internal surface area which can be tuned to attract water. When this material is placed between a surface painted black to absorb solar heat, and a lower surface kept at the same temperature as the outside air, water is released from the pores as vapour – the difference in temperature means the water will drip down and collect on the cooler surface.

In tests, 1kg of the foam could collect about 2.8 litres of fresh water per day from very dry air with a humidity of just 20%. By tuning the surface area of the foam, the team has devised systems which will work effectively at higher percentages too.

Further refinements also look promising.

While the present incarnation can collect water at up to about 25% of its own weight, hopes are high this can be increased to 50% with further tuning. n

May 2017

Solid ground Velodyne has unveiled its new fixed-laser, solid-state Velarray™ LiDAR (Light Detection and Ranging) sensor.

The company is hoping to pull ahead of the market in releasing the system for new autonomous vehicle applications. “The Velarray enables not only fully autonomous vehicles, but also ADAS systems such as adaptive cruise control, while at the same time providing a miniature form factor and mass production target prices,” said company president and CCO Mike Jellen. “It offers a unique value proposition empowering a vehicle system that improves the safe driving experience, alongside an upgraded path to full autonomy.”

The newest sensor brings high performance in a small package of 125mm x 50mm x 55mm. It can be embedded into the front, sides and corners of vehicles. It provides up to a 120-degree horizontal and 35-degree vertical field-of-view, with a 200-metre range even for low-reflectivity objects.

It has a target price in the hundreds of dollars when produced in mass volumes, which the company hopes will begin in 2018, although sample units will be available by the end of 2017. n

The heat is on All throughout the last century’s advances in computing, cooling has remained a perpetual problem. Various methods exist, and are more or less useful depending on computer size and application, but computers, on the whole, will run hot.

Turning the problem on its head, however, researchers at the University of NebraskaLincoln decided to use that excess heat as an energy source to enable computing at ultra-high temperatures.

“If you think about it, whatever you do with electricity you should (also) be able to do with heat, because they are

similar in many ways,” said Sidy Ndao, assistant professor of mechanical and materials engineering. “In principle, they are both energy carriers. If you could control heat, you could use it to do computing and avoid the problem of overheating.”

Ndao co-authored a paper with graduate student Mahmoud Elzouka, published in the March edition of Scientific Reports, documenting their development of a device that worked at temperatures approaching 630°F (330°C). Ndao said he expected the device could eventually work in heat as extreme as 1,300°F (700°C).

“We are basically creating a thermal computer,” Ndao said. “It could be used in space exploration, for exploring the core of the earth, for oil drilling, for many applications. It could allow us to do calculations and process data in real time in places where we haven’t been able to do so before.”

That energy could be derived from thousands of potential waste

NEWSBASE

heat resources – industrial and domestic.

According to their paper, the proof of concept device managed a maximum rectification of 10.9% at terminal temperatures of 375 and 530 K (102°C and 257°C). The next step is making the device more efficient and making a physical computer that could work in the highest of temperatures, Ndao has said. n

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Fuzzy logic for NASA In collaboration with NASA, Rice University laboratory of materials scientist Pulickel Ajayan has developed “fuzzy fibres” of silicon carbide to strengthen composites used in space missions. These fibres act like Velcro, helping to reinforce the composites used in advanced rocket engines, which must withstand temperatures of up to 1,600°C. Current ceramic composites use similar fibres; however, these can crack or become brittle when exposed to oxygen, which can change the fibre’s composition.

Rice embedded silicon carbide nanotubes and nanowires into the surface of NASA’s fibres. The exposed sections are curly and act like the hooks and loops of Velcro, but on a nanoscale. This creates very strong interlocking connections where these sections tangle, meaning they less prone to cracking and are sealed, preventing contact with oxygen.

The hooks and loops were made by bathing silicon carbide fibre in an iron catalyst using water-assisted chemical vapour deposition to embed a carpet of carbon nanotubes directly into the surface. They were then heated in silicon nanopowder at high temperature, converting the carbon nanotubes to the “fuzzy” silicon carbide.

Lead researchers Amelia Hart and Chandra Sekhar Tiwary hope that the innovation will enable turbo engines to become significantly lighter. “Before they used silicon carbide composites, many engine parts were made of nickel superalloys that had to incorporate a cooling system, which added weight to the whole thing,” Tiwary said.

“By switching to ceramic matrix composites, they could take out the cooling system and go to higher temperatures. Our material will allow the creation of larger, longer-lasting turbo jet engines that go to higher temperatures than ever before.” n

Got the bug While vdrones are now being outfitted to perform numerous new tasks, they still struggle with old problems. Most drone collisions are likely to be catastrophic for the system and its payload, not to mention whatever it is they happen to collide with.

Manufacturers are thus turning to interesting methods of increasing their robustness.

Designers at Floreano Lab, NCCR Robotics and EPFL have explored one new approach to making crash-resilient quadcopters: making them softer. Stefano Mintchev, the lead researcher on the project, has developed a quadcopter based on the dual stiffness properties seen in insect wings.

These wings are composed of sections

made of cuticle, a stiff material that takes the load-bearing portion of the wing, connected with flexible joints made of the protein resilin, which is shock-absorbent and compliant.

Mintchev’s design features a central case NEWSBASE

and a 0.3-mm thick fibreglass external frame with four arms held together by four magnetic joints. The four magnetic joints connect the frame to the central case and hold the frame in place during flight. During a collision these magnetic joints collapse, allowing the frame to disengage and deform without damaging itself or the inner core. Soft elastic bands ensure that the frame is held close enough in place that the magnets snap back after the collision.

The quadcopter was tested at drop heights of up to 2m and returned to its original state – a process which was repeated 50 times.

The research may help to develop alternative drone designs, although it may be a while before this one can be entrusted with a sensitive payload … n

Organised By:

Shaping the Continent’s Future in Upstream Oil & Gas

Including 79th PetroAfricanus Dinner 24th May, Jasper Peijs, Vice President for Exploration, Africa, BP, London, UK 8th Global Women Petroleum & Energy Luncheon 25th May, Sandy Stash, Group Vice President, Safety, Sustainability and External Affairs, Tullow Oil, London, UK

24th - 25th May 2017 The Waldorf Hilton, London, United Kingdom

www.africa-independentsforum.com Sponsors

Supporting Sponsors

Supporting Airline Partner

Harry Harrison-Sumter harry.sumter@ite-events.com

London: +44 207 596 5065 Johannesburg: +27 11 880 7052

Contact: Sonika Greyvenstein sonika.greyvenstein@ite-events.com

Amanda Wellbeloved Amanda.Wellbeloved@ite-events.com

May 2017

InnovOil

LNG at SEA SPECIAL SUPPLEMENT Pages 13-21

POST-PANAMAX POWER DSME and DNV GL on their latest carrier design Page 14

FUEL OF THE FUTURE Chart Industries’ LNG–powered innovations Page 19

TRANSFER WINDOW

Wärtsilä’s jettyless LNG system Page 20

NEWSBASE

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InnovOil

May 2017

LNG at SEA

DSME, DNV look to post-Panamax DSME and DNV GL discuss the results of a new collaborative project to design a larger, more efficient LNG carrier for the post-Panamax age

L

NG carriers are changing. As Arctic trade routes and frontier projects like Yamal LNG open up to the north, and with the widening of the Panama Canal ongoing in Central America, new designs are creating bigger, more powerful and more efficient vessels.

In its annual report, the International Gas Union (IGU) noted that LNG was playing an essential role in the marine shipping sector, with 31 newbuilds added to the shipping fleet in 2016, an increase of around 7% to 439 vessels in total. Only two vessels were scrapped in the year.

However, all of this comes during a glut of gas supply. Average charter rates fell below US$20,000 per day during the year, and a new tranche of newbuilds in 2017 may exert even further pressure in the short term, before supply and demand begin to level out post-2020. The result is that new designs being drawn up currently are concerned with maximising efficiency and cargo capacity, and that means better propulsion, hull profiling and increased data capture.

At this year’s Gastech conference in Tokyo, Daewoo Shipbuilding & Marine Engineering (DSME) and classification society DNV GL presented the results of a joint development project (JDP) for the design of one such innovative LNG carrier. According to DNV, the project focused on producing a design “which an owner can take straight to the yard” in addition to being prepared for incoming regulations and market trends.

“When we look at today’s LNG market we predict that in the years to come we will see the rise of post-Panamax LNG carrier designs which are dimensioned to fit the new Panama Canal. Capacities of over 175,000 cubic metres are feasible given the new restrictions,” commented DNV GL’s maritime business director for gas carriers, Johan Petter Tutturen, at the time.

The Panama Canal expansion will see the route accommodate vessels of up to 180,000 cubic metres, a figure borne out in the IGU’s record, which notes that the average orderbook vessel capacity at the end of 2016 was 172,000 cubic metres.

MCTIB design specifications

to this JDP,” Tutturen told InnovOil. “In the past DNV GL had done the LNGreen I project with HHI (as well as GTT and GasLog), followed by LNGreen II which is ongoing. Furthermore, we had the LPGreen JDP, also with HHI and Consolidated Marine Management and Wärtsilä. The common goal for these projects was to carry as much cargo as possible at the lowest cost, meaning the focus was put on optimising the hull lines and propulsion.” For this latest project, DSME wanted to widen the scope to include other innovations, such as its MCTIB fuel tanks and a partial re-liquefaction system (PRS).

The JDP began with a comprehensive market study to help determine what design features would be most important. “We looked at trends, trading routes, which geographical regions LNG was shipped (out from and

Taking the initiative “It was DSME that took the initiative NEWSBASE

Min design temperature of -165ºC

within), the LNG trading mechanisms – such as an increase in spot trade, (accepting the fact that more cargoes may be re-sold during voyage, hence the trading pattern may be more difficult to predict),” he said.

Described as the “DSME Post-Panamax 200K LNG Carrier,” its new design is 300m long by 48.9m wide, with a depth of 27.5m and a designed draft of 11.9m. Four cargo tanks allow for 200,000 cubic metres using membrane-type cargo containment system (CCS) or 170,000 cubic metres using DSME’s high-manganese steel Type B tank, known as MCTIB. It is also suitable for conversion into a floating storage and regasification unit (FSRU).

“The maximum allowable width

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LNG at SEA Below: Johan Petter Tutturen, DNV GL – Maritime Business Director Gas Carriers

of vessels passing through the new Panama Canal is 49 metres,” Tutturen said. “It was natural to take advantage of this width increase, while the other main particulars were kept as-is for a vessel being built today.”

DNV draws attention to the shift towards lower, more energy-efficient transit speeds.

As result, the JDP vessel design features an optimised hull and propulsion system, aimed at three different operating profiles on a standard Trans-Pacific route: 19.5, 16 and 12 knots. In calm water, these are 6%, 2% and 5% more efficient over the reference design at each operating profile respectively. “The engines become more energy-efficient: hence you will have surplus boil-off at low speed – that’s why the PRS was introduced,” Tutturen continued.

The project participants noted that over 700 different hull designs were explored and run through DNV GL’s hydrodynamic analysis software Wasim, as well as statistics and Reynolds-averaged Navier-Stokes (RANS) simulations for determining wave resistance. “We have run a full hydrodynamic analysis for a 192K vessel, but DSME wants to increase the size to 200K, which is now being worked on,” he said.

Left: DSME’s latest carrier design

The design also incorporates directcoupled, two-stroke dual-fuel (DF) main engines and DF auxiliary engines, which use LNG as their primary fuel. A combined gas turbine, electric and steam (COGES) propulsion system is used for the optimised machinery.

Extra in the tank The MCTIB was chosen as the optimal choice to hold the portion of the boil-off gas used as LNG fuel, and has been tested in closed, mock-up conditions using liquid nitrogen (LN2). DNV notes that the material’s sound tensile properties enable high performance and high gas capacity at low cost.

“It is a manganese-based alloy steel and shares the same crystal structure with austenitic stainless steel,” Tutturen added. “As you can see [in the comparison table], the high manganese steel has high potential competitiveness than others.” This also allows for flexible tank shapes while remaining slosh-free, thereby not imposing any limitations on filling.

The design also incorporates DSME’s SloT® (Ship Internet of Things) technology and wireless computer network and integration system Smartship 4.0. Tuttern elaborated: “In short it means [taking] advantage of all data collected while in operation to facilitate a more robust maintenance scheme and cyber-security, as well as provide a system where all components manage to “talk” with each other.”

Despite the influx of newbuilds on their way in the coming years, the JDP partners seem confident that the added efficiency and capabilities of the post-Panamax design will allow it to hold its own in a tough market. Only time will tell, but their focus on the key driver – carrying as much cargo as possible at the lowest cost – should help keep DSME’s order book healthy. n Contact: Nikos Späth

Email: Nikos.Spaeth@dnvgl.com Web: www.dnvgl.com www.dsme.co.kr

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May 2017

LNG at SEA

Bunkering down on LNG fuel NewsBase Research (NBR) chairman Gav Don considers whether LNG-powered ships are a viable answer to incoming MARPOL regulations

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S LNG on the cusp of replacing Liquid Fuels in the market for ship propulsion?

A quick glance at the International Convention on Prevention of Pollution from Ships (MARPOL to its friends) might make one think so. MARPOL sets standards for NOx and SOx emissions by marine engines, and it is now in force.

Permitted emissions are graduated in Tiers, according to the age of the ship and its engine speed in RPM, and also by area, with the coasts of (broadly) the US and Europe sitting in the most stringent areas. So how big is the challenge?

International bunkers currently account for about 5% of world Liquids demand, and have reliably added about 100,000 barrels per day to world demand each year, making their demand “upsteps” equal to most large economies. Without going into too much (expensive) detail, some patterns jump out of NBR’s research.

First, unlike a Liquids Intensity Curve, which shows how individual economies grow, and then shrink, their Liquids demand over time, Bunkers demand has marched in almost rigid lock-step with global GDP growth for 30 years. Plotting a regression between them shows a Rho (coefficient) of 0.97.

The problem of ship emissions is therefore unlikely to be solved by getting rid of ships.

New SOx There are many options for complying with MARPOL that do not require mass write-off of existing ship propulsion plant.

The simplest one is to use (more expensive) low-sulphur fuels. With bunkers demand at 4.5m bpd that is a stretch, but expect a small boom for refineries which will invest in hydrotreating plant.

That may not be necessary. A Nevadabased early stage company – Alternative Petroleum Techologies – has announced a low temperature de-sulphurisation process that can be applied at bunker sites instead of in refineries. The process is not yet proven at scale, but APT recently raised an undisclosed capital sum from Atlanta-based West Mountain to do just that.

While the industry is waiting there are other routes to SOx and NOx compliance.

Selective Catalytic Reduction works to reduce NOx to N2, but only if the operating temperature is kept in a rather tight range – and that still requires a supply of Urea, making it complicated and troublesome.

Another solution is Exhaust Gas Recirculation. NOx generation can be reduced by half, or more, by cooling down the combustion process. That can be achieved either by adding water to the inlet air or by closing inlet valves early. These solutions are all aimed at NOx, but not SOx. A Singapore company – EcoSpec – has developed a patented exhaust washing system (CSNOx) that claims to remove almost all SOx and NOx using just seawater. InnovOil does not have any technical details at the time of writing, so cannot comment in full, but the

NEWSBASE

shipping industry has not embraced CSNOx wholeheartedly yet, or even at all. Canada Steamship Lines installed a CSNOx unit in its 22,000 tonne Spruceglen, but detailed results are not in the public domain, and Caribbean Cruise Lines is also testing a unit.

Liquids stay afloat The biggest solution, and the one that probably gives the Liquids industry the most sleepless nights, is to abandon liquid bunkers altogether and move ship propulsion to LNG. There is no great technical challenge in using methane instead of fuel oil, and methane brings SOx, NOx, CO2 and cost wins, being cheaper and better on all those metrics.

The challenge comes from three directions – first, the shipping

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LNG at SEA Artists impressions of newly commisioned LNG-powered ships.

Left: Carnival Cruises has three vessels on order.

Below: The Balearia ferry company has two LNG ferries on order to operate on the route joining Spain to Majorca

industry already owns a very large quantity of conventional Liquids plant, and is not going to write that plant off on a MARPOL whim.

So, ship life cycles will mean Liquid bunkers are going to be around for a very long time to come.

Second, ship owners and ship financiers are highly conservative creatures who prefer other people to innovate (and make expensive mistakes) before reluctantly joining in.

EcoSpec is probably learning that lesson right now, with a slow take-up of its solution. It is not just the owners who are conservative.

Ship personnel would need to acquire a whole set of skills around handling cryogenic liquids which explode violently if allowed to get out of control.

Third, there is presently no global marine

LNG re-fuelling infrastructure to speak of.

So, if you did commission an LNG-fuelled ship today you would be locking yourself to tiny and inconvenient corners of the world shipping market. Port operators will be reluctant to build LNG depots until there is a decent population of customers, and they will also be reluctant to take on a whole new and exciting portfolio of product risk posed by explosive methane. It will take some time for this chicken and egg to decide which goes first.

That said, there are some early movers in LNG powered propulsion. Not surprisingly this comes from two sectors with above-average pressure to be environmental, and with operations that revolve around a single base port – ferries and

NEWSBASE

cruise liners. The Balearia ferry company has two LNG ferries on order to operate on the route joining Spain to Majorca, and Carnival Cruises has three LNG ships on order. In fact 13 of 73 cruise liners currently on order are powered by LNG. As these operations prove systems, create a pool of trained personnel, demonstrate that risks are manageable, promote the construction of LNG fuel depots, and show cost and environmental savings, others will follow.

NBR’s research suggests that the bunkers market will eventually flip into a state in which the majority of ship miles are powered by LNG. That will take longer than MARPOL would like, but not as long as the Liquids industry would. Until then, ship operators will have to use the piecemeal innovations and plant fixes mentioned above. n

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HHI unveils glycol regas system

May 2017

LNG at SEA

South Korean shipbuilder does away with seawater, increasing efficiency and reducing the risk of corrosion

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OUTH Korea’s Hyundai Heavy Industries (HHI) has independently developed an advanced LNG regasification system using glycol, which it claims will further improve its competitiveness in the LNG shipbuilding market.

HHI said on March 31 that it had held a demonstration ceremony at its Ulsan shipyard for the installation of the regas system in a 170,000 cubic metre floating storage and regasification unit (FSRU) under construction, in an event attended by Korean and foreign ship-owners and ship classification companies.

HHI said the new regasification system would increase the efficiency and safety of FSRUs that receive LNG from offloading carriers and send vaporised gas by pipeline to onshore receiving facilities.

In the past, seawater and propane gas were used to heat LNG. However, the new technology is an indirect heating LNG regasification system using glycol, a type of alcohol which is used as a material in synthetic fibres and anti-freeze, and has a lower solidifying point as the heating medium.

“Since the glycol regasification process is free from saltiness unlike a system that uses seawater, it can minimise corrosion in major equipment including heat exchangers, and it can also lower the risk of explosion that a system using propane may be exposed to,” HHI said in a statement.

The company secured an approval in principle (AIP) for its regasification system from Lloyd’s Register in February and is also seeking to receive class AIP from global leading shipbuilders, in addition to applying for a patent at home and abroad.

HHI said the first LNG-FSRU equipped with the new regasification system would be delivered in early 2019. HHI delivered the world’s first newbuild LNG FSRU to Norway’s Hoegh LNG back in 2014. It also claims to be the only Korean shipbuilder that can both build membrane and mosstype LNG carriers.

New orders The new regasification process marks the latest in a string of LNG-based innovations HHI is developing. Last month, the shipbuilder signed a contract with NEWSBASE

Sovcomflot for the construction of the first LNG-burning Aframax crude tankers ever to be built. The US$240 million order covers the construction of four 114,000 dwt Ice Class 1A. The first of the 250-metre vessels will be delivered in the third quarter of 2018 and will be chartered to Royal Dutch Shell, whose Western LNG unit will also supply them with bunkered LNG fuel via two supply points in Rotterdam and the Baltics.

In another recent project, HHI, Lloyd’s Register and the Hyundai Mipo Dockyard (HMD) have signed a joint development project (JDP) for a ship-to-ship LNG bunkering compatibility study.

There are currently no guidelines for the design or practice of safe ship-to-ship LNG bunkering, despite its effectiveness for both ship and port operators. The programme will therefore review the design requirements between 6.6-tonne LNG bunkering ships and 14-tonne TEU LNGfuelled container ships, with the aim of verifying best practices. The study will then “evaluate the right direction for LNG supply infrastructure.” n

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LNG at SEA

Charting the future of marine LNG Chart Industries explores how the demands of the marine industry are influencing the design and innovation behind its LNG systems

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EADY or not, the marine industry is decarbonising. In the wake of the COP21 agreement and growing commitments from global leaders and regulatory bodies, regulations on marine pollution are only likely to become more stringent, and deadlines are already approaching. Under MARPOL Annex VI, for example, the global cap for vessel sulphur emissions will be lowered from the current 3.50% to 0.50% from January 2020. As a result, the industry is looking to technology and cleaner fuels to ensure compliance.

For many operators, LNG-fuelled vessels are the natural choice. A relative abundance of feedstock, cost efficiency and flexibility, in addition to reduced SOx and NOx emissions, are driving the change. By 2020, DNV GL expects several hundred vessels to be running on LNG (excluding LNG carrier vessels).

Global cryogenic engineering and supply company Chart Industries is enabling these changes first-hand, throughout all aspects of the LNG supply chain. “We expect LNG will take a predominant place during the coming decades in the marine fuel mix. Apart from fuel pricing and emission aspects, there are many other advantages of running on gas, which the majority of ship-owners/ operators are still unaware of today. Think about engine room operations, maintenance logistics, crew comfort and health,” Joris van Kreij, responsible for global business development for Marine LNG Solutions at Chart, told InnovOil. As one of the largest single-source LNG equipment and solutions providers, its services cover liquefaction, distribution, storage and end-use, and the company has

undertaken a number of innovative marinebased LNG projects.

World-firsts One project, finalised in 2012, involved the design and manufacture of a first-of-itskind LNG fuel system for the Francisco, a high-speed catamaran ferry in Argentina.

Touted by designer and builder Incat to be the “fastest ferry in the world” the flexfuel Francisco is capable of carrying 1,000 passengers and 150 cars, and will manage 50 knots when fully laden, taking just over 2 hours to make trips between Buenos Aires and Montevideo. It was the first ferry built according to High Speed Craft (HSC) Code for LNG-fuelled turbines.

Chart’s innovations are concealed in the vessel’s twin hulls. Two General Electric LM2500 gas turbines are powered by twin 43 cubic metre, DNV-approved cryogenic tanks, which were engineered and manufactured in Chart’s Decin facility in the Czech Republic.

These identical fuelling systems can operate independently, and heat recovered from the turbine exhaust gas is re-used to evaporate LNG. The system includes a pump, vaporiser, valves, instrumentation, engine feed line, water/glycol heating circuit, bunkering lines, controls and a nitrogen system.

Because size, weight and safety were fundamental to the project, Chart applied unconventional features like a low pressure lightweight tank using super insulation along with an integrated stainless steel ‘cold box’, engineered to house the control system, cryogenic pump and vaporisation system.

The company has also been involved in innovative bunkering and LNG-to-power projects. A recent contract in Germany NEWSBASE

required Chart to build an LNG fuelling system for Hummel, a hybrid power plant barge which provides energy to ships during layovers in the port of Hamburg. Hummel also supplies electricity and heat to the port’s container terminal during winter.

Chart supplied shipbuilder Becker Marine Systems with storage tanks, featuring Chart Vacuum Technology®, capable of holding up to 43 cubic metres – the maximum payload available for the container size – eliminating the need for a fixed tank with a separate bunkering station (although the system retains the option to use bunkers for filling).

The fully modular fuelling system is housed in two 40-foot ISO containers, and includes a skid-mounted gas processing unit, interconnecting pipe work, control and safety appliances. The system provides cryogenic storage for almost 23,000 gallons (105 cubic metres) of LNG, and is capable of powering up to seven 1,555-kW CAT3516 generators.

The company continues to work on pioneering projects throughout the sector.

“We innovate purely based on what we see that customers are worried about.

While ship-owners want reliability and low maintenance, shipyards typically aim for economical solutions with smart ways to reduce costs,” van Kreij added.

To see how Chart could provide innovation and expertise on your LNG project, contact the company via the information below.. n Contact: Joris van Kreij

Tel: +31 657 884 215 Email: joris.vankreij@chartindustries.com Web: www.chartlng.com

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May 2017

LNG at SEA

No jetty? No problem Wartsila has led the development of a new “jettyless” LNG transfer system that it hopes will open up small-scale LNG power developments in remote areas

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ESPITE the increasing interest in LNG as a power source for remote communities, its actual uptake has been limited, mainly as a result of the major civil works often required to construct the necessary harbours, quaysides and jetties.

A lack of available investment, as well as environmental concerns over building work, may thus be holding back the technology from widespread adoption.

In response, Finland’s Wartsila has collaborated on a “jettyless” LNG supply concept that seeks to provide an alternative solution for transferring LNG from ship to shore on islands and other coastal areas.

Alongside marine design consultancy Houlder and hose supplier Trelleborg, the consortium announced the introduction of the infrastructure system, aimed primarily at small to mid-scale LNG power plants, at the start of April.

The partners said that their newly developed concept allowed the transfer of LNG from small to mid-scale carriers to

onshore or floating storage and regasification terminals where it was not feasible to build a jetty for mooring the vessel.

The system uses a so-called floating transfer terminal (FTT), developed by

The Floating Transfer Terminal with onshore connected floating hoses NEWSBASE

Houlder, and is equipped with a self-propelled barge to transport LNG vessels moored up to 800 metres offshore. The terminal is outfitted with an integrated transfer arm, also developed by Houlder and KLAW LNG. Gianpaolo Benedetti, Houlder’s LNG business development manager, described the floating transfer terminal as “taking the jetty to the LNG vessel, rather than have the LNG vessel come to the jetty.”

Additionally, Trelleborg Cryoline LNG floating hoses are also used to transfer the LNG and boil-off gas between the barge and any shore facility. They work at a maximum operating pressure of 20 bar and can be used in floating, submarine or aerial configurations, with various hose sizes supplied depending on the pressure of the gas supply. They feature an integrated leak monitoring system, and when not in use, are stored onshore with a customdesigned reel system.

According to Wartsila estimates provided to InnovOil, the jettyless concept could be used at distances of up to 600m from the shore.

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LNG at SEA The jettlyess concept connects onshore infrastructure to a platform via floating hoses

Floating an idea Wartsila LNG solutions sales and marketing director Kenneth Engblom spoke with InnovOil regarding the system’s development.

As with many such innovations, he is keen to point out that the project was prompted by requests from clients. “We are the LNG solutions provider and we can build traditional jetties, but we hope to build simpler, better and faster solutions. It’s not in our interest to execute complicated, expensive, time-consuming projects – our only interest is to get LNG to our clients as cheap as possible.”

In looking to make these projects cheaper and simpler, Wartsila brought cable firm Trelleborg into the picture. The company had recently qualified the world’s first floating LNG (FLNG) transfer hose – an innovation which would go some way towards solving the problem of delivering LNG out to sea without a jetty. “We then thought about different solutions – for example having it permanently floating or designing a small

ship to bring it in and out – and that’s when we brought in Houlder.” In response, the engineering consultancy designed the floating transfer mechanism to complete the concept.

Although the industry may just be waking up to new equipment like floating hoses, nothing here is unproven. “There are really no new components,” Engblom says. “The loading arm has been on the market before, the hose is new but it was approved last year, the emergency break from the FTT has been there before – it’s just combining these existing components into a new solution.”

In addition to environmental benefits, the FTT also enables significant cost reductions compared to a jetty. While Wartsila is reluctant to offer a set figure – prices usually depend on a number of engineering and supply factors – these can make a significant dent in project capex, especially in such remote locations and areas where labour and construction may be difficult. “The FTT is manufactured in a workshop, so all of that NEWSBASE

work that would otherwise happen on site is done in a factory. You still have to have something onshore, somewhere to store the FTT and hose reel, which requires some site installation, but there is a big cost benefit,” Engblom adds.

He believes the concept will be of most interest to developers of remote, small-scale LNG-to-power projects, particularly in Southeast Asia, the Caribbean and even the Mediterranean.

It is still early days for commercial offering of the system, but Engblom is optimistic that Wartsila’s clients will be quick to see its value.

And, as small-scale LNG production and consumption become even more widespread, the space and cost economy of the FTT concept may become the preference. The days of the LNG jetty might already be numbered. n Contact: Kenneth Engblom

Tel: +358 40 756 6686 Email: kenneth.engblom@wartsila.com Web: www.wartsila.com

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InnovOil

Working on the chain, gang

May 2017

Blockchain technology is touted to transform financial markets. Andrew Dykes explores what the impact might be on the energy sector, both in commodities markets and the field

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OU can’t go anywhere without hearing about it these days.

No industry is safe, no task too complex. Blockchain has threatened to shake up financial markets and, increasingly, hopefuls are seeking new homes for the technology, including the oil and gas sector. Most obviously, blockchain can simplify commodity contracts but there is scope for improvements in how the industry handles logistics and inventories.

The blockchain is based on the same principles that underpin the world’s most well-known cryptocurrency, Bitcoin.

Blockchain algorithms are a method of encoding peer-to-peer transactions. These transactions are recorded and stored together in a timestamped “block” of data, which is then logged and stored in a decentralised database. When created, each block is assigned a unique algorithmic hash code based on the information it contains, as well as the block before it (chaining them together).

If any piece of transaction data does not match the block, the verification algorithm will not produce the correct hash code, and will flag an error. This process allows transactions to be continuously stored and verified by the parties using the system, and more blocks added to the chain, but the transaction cannot be revised. The network of “distributed ledgers” also ensures that all participants in the contract or transaction use the same, correct information.

The Big Four accounting firms – KPMG, PwC, Deloitte and EY – in particular have come out swinging, with banks following suit. According to a 2016 IBM survey, 15% of global banks intend to roll out full-scale commercial blockchain products in 2017 – an uptake it said was “dramatically faster” than anticipated, and light years ahead of the 5-10 years expected by many in the industry.

The benefits of such a system are said to be increased digital security, data transparency, the removal of duplication and better automation, which are all worthy outcomes. One would be forgiven, though, for questioning where these technologies may fit into the energy industry. Yet, if the hype is to be believed, energy and its associated businesses are ripe for a blockchain-based transformation.

Block party The main scope for blockchain in the energy sector lies in the simplification of contracting and commodity trading. “Blockchain has increasing relevance to the oil and gas industry as a mechanism to reduce operating cost. Even more relevant, however, is [its] ability to transform the contracting process given its aptitude to provide a secure form of collaboration across multiple parties” EY oil & gas strategy leader Fay Shong recently stated.

The creation of smarter, blockchain-based contracts can streamline and automate large portions of the trading process. PwC has highlighted the lengthy process of confirmations, actualisation of volumes and the numerous forms of reconciliation that may follow a trade. All of these require costly and time-consuming work in the back offices of traders, banks, and clearing houses – in some cases by up to a dozen parties. Much of the system’s benefits – as far as banks and accountants see it – is in removing these intermediaries altogether.

“Rather than each post-trade participant maintaining the same data in their individual ledgers, a master ledger shared among those participants would eliminate the need for costly reconciliation processes,” Moody’s SVP Robard Williams commented in a recent note.

Smart contracts do also bring other niche advantages, such as the ability to execute NEWSBASE

a trade only once certain parameters have been met, e.g. a certain price threshold or only once a slot become available at a cargoloading destination. IBM suggested that: “If import terminals received data from bills of lading earlier in the process, terminals could plan and execute more efficiently and without privacy concerns. Blockchain technology could make appropriate data visible in near real-time – for example, the departure time and weight of containers – while making inaccessible the information about the owners and value of the cargo.”

PwC notes that such contracts “allow seamless tracking of ownership … coupled with the ability to verify data at both ends.” In the case of an oil cargo, for example, it would ensure that funds are transferred to the seller once the quantity and quality of that cargo has been confirmed.

May 2017

Experiments in the electricity trading sector are already in progress, and commodity traders are beginning to catch on. Most recently, ING and Société Générale Corporate & Investment Banking concluded the first oil trade using a prototype blockchain platform. During London’s IP Week, both groups demonstrated a live trade with trading house Mercuria.

The system, dubbed “Easy Trading Connect,” was created to offer a standardised, digital and paperless trading system. The experiment involved an oil cargo shipment containing African crude, which was sold three times on its way to China. The demonstration included traders, banks, an agent and an inspector, all of whom interacted with the transaction directly via the platform.

At its most basic, the technology simplifies

InnovOil

the means of certifying and recording the documents and the sale of goods, but the implications are significant. According to ING, the platform reduced the average total time for a bank to complete its role in the transaction from approximately three hours to 25 minutes. Replicated over hundreds of trades, that frees up considerable staff time and could lower the amount of capital required by traders to cover the cost of oil in transit.

ING Trade & Commodity Finance director Patrick Arnaud added: “The commodity finance industry is hampered by nature by inefficiencies and outdated procedures. By applying blockchain technology, we expect that we can eliminate a lot of these, making the overall process faster and more cost effective and the tests we have been able to carry out have proved this.”

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Unchained potential However, it is not just downstream trading that technologists are targeting. Upstream, PwC sees potential to apply these systems to asset management and service contracts.

Using the smart contract model “owners can be informed of production volumes in real time and compensated by working interest as soon as the drilled commodity is priced and sold,” the group noted.

That extends to midstream infrastructure, such as pipelines, where throughput can be monitored in real time, compared against expected volume and transactions can then be initiated once each participant has verified.

In addition, blockchain architecture could help solve issues around secure upstream data storage, EY believes. “As the oil and gas industry increasingly leverages sensor technology across upstream and downstream

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In many cases, this uncertainty can be explained by an insufficient understanding of how blockchains work.

Essentially, a blockchain is a digital contract permitting an individual party to conduct and bill a transaction (e.g. a sale of electricity) directly (peer-to-peer) with another party. The peer-to-peer concept means that all transactions are stored on a network of computers consisting of the computers of the provider customer participating assets, theand ability for blockchain to store in a transaction, as well as of the transactions and accounting datacomputers directly on these devices can compress process time by connecting assets directly to services Figure 2:” The blockchain contracts, Shong explains. process

May 2017

The supply chain is ripe for simplification Regulators must also catch up. EY, too. While various logistics and tracking for example, questions how cross-border systems are used for shipping oilfield payments should be taxed given that these equipment, many are not linked directly would be instantaneously routed through to contract fulfilment and payment. The machines across the world. More legislation smart contract model for commodity trades on data security and ownership will be could be applied to the provision of services, necessary too, to establish best practices and enabling payment once the equipment determine who is responsible in the event of reaches its destination, or the service contract a breach. has been initiated.

Large swathes of the trading business are While promising, some of these particular affected by this potential disruption, with applications have the hallmarks of oversome facing an existential battle should the complexity. Certainly, real-time asset technology gain ground. It may, though, be monitoring and connected technologies better to regard blockchain as evolutionary, are transforming how operators, service rather than revolutionary. providers and OEMs look at their business.

“Existing clearing and settlement But many versions of these systems already incumbents will remain largely in place,” exist in internal networks. In external Moody’s said. “Innovative incumbents transactions, whether for security or out of are already making large investments in habit, many oilfield companies are likely to blockchain technology andconsumers? are collaborating Blockchain – an opportunity for energy producers and 5 remain with the status quo. with one another, as well as with start-up companies to create sector-wide solutions.”

Weak links Meanwhile, the savings offered by the Successful use of blockchain technology adoption of smarter, digital contracts would requires a number of things to happen. In reduce reconciliation costs and “help offset particular, as the CFO of global trading lower revenues that custodians, clearing of many other network participants. house Trafigura, Christophe Salmon, recently houses and/or registrars might suffer” as a Traditional intermediaries, e.g. a bank, remarked to the FT, the technology must result of faster settlement. are no longer required under this model, be adopted broadly.

The majority of major Certainly we are about to see an influx of as the other participants in the network traders and oil refiners would need to take these “innovative incumbents.” The trading act as witnesses to each transaction up to such a system in order to make the market in particular will look very different carried out between a provider and a platform viable. in just a few short years as these systems, customer, and as such can afterwards That network would need to be scaled or systems very like them, help to automate also provide confirmation of the far beyond the size of trials used at present. labour-intensive and paperwork-heavy details of a transaction, because all Moreover, as many have pointed out, the procedures.

But elsewhere, the widespread relevant information is distributed to necessity of being able to trade with as any adoption of the technology will depend on the network and stored locally on the computers all participants. partners asof possible would likely result in a how far its benefits can be communicated to trend towards a single blockchain platform. notoriously conservative oil executives – and That platform would either be public (too that may be a harder sell in a market which transparent and open for many traders) or is rarely the first to welcome new kids on the private (and potentially anti-competitive). block. n

The Blockchain process

A provider and a customer agree a transaction

The transaction is combined with other transactions made during the same period to create a data block

The data block is stored in the decentralised global network in a tamper-proof manner and thus verified

NEWSBASE

The verified block is combined with all other blocks previously verified, thereby creating a (continuously growing) blockchain

The transaction is confirmed to both parties

Graphic: PWC

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InnovOil

May 2017

Gold-plated gas detection A partnership between Duke University and SRICO has created a faster, cheaper solution for gas detection using an intriguing arrangement of metamaterials

W

HILE some of the industry’s most impressive breakthroughs are the result of larger equipment, and bigger scope, it will be the smallest sensors that drive the next revolution. Having seen major advances in sensors for seismic surveys and oil analysis, gas detection is proving to be one of the most interesting fields for the technology.

Most recently, materials scientists and engineers at Duke University and optoelectronic materials company SRICO have helped develop a sensor that is fast, sensitive and efficient enough to detect specific wavelengths of electromagnetic energy while on the move – an innovation that could improve how methane or natural gas leaks are detected.

Central to the technology are metamaterials. These are carefully arranged structures of materials, usually metals and plastics, which exhibit properties not found in the base materials themselves. The exact shape, size and alignment of these patterned structures can determine these properties, and allow them to interact with electromagnetic waves in unnatural ways.

In this case, patterns of metal are interlaid with extremely thin slices of perfect

crystals, allowing the tiny device to detect invisible infrared signatures emitted by various kinds of gases, plastics and other sources.

“The benefit of using metamaterials is that different components required in a detector can be combined into one feature,” said Willie Padilla, professor of electrical and computer engineering at Duke. “That simplification gains you a lot of efficiency.”

That has allowed Padilla and his team to build a prototype detector that is smaller, lighter, more powerful and apparently cheaper than the current alternative. Their results were presented in the Optica journal in February 2017.

A good conductor In a typical thermal detector, infrared light waves are absorbed and converted into heat by a black substance, essentially soot. That heat is conducted to a separate component that creates an electrical signal which can be read.

However, that process takes time, meaning measurements can be slow, and only by overlaying filters or a complex system of moving mirrors can the sensor be set up to identify specific wavelengths.

The metamaterial sensor avoids these issues. Each section of the detector consists of a pattern of gold sitting on top NEWSBASE

of lithium niobate crystal. This crystal is pyroelectric, generating an electrical charge when it is heated.

SRICO is able to slice these lithium crystals to thicknesses of 600 nanometres using a focused ion beam (FIB), a technique common in the semiconductor and materials industry. This reduces the potential for defects in the crystalline structure – meaning the sensor is more accurate and less prone to background noise – and means the slices are thinner, allowing the crystal to heat up more quickly and producing a more sensitive detector.

The resulting crystal layer is so thin that light would normally pass through it without being absorbed. However, by adjusting the pattern in the top layer of gold, the properties of the crystal are altered, causing the pixel to absorb only a specific range of electromagnetic frequencies. This removes the need for the separate filters required by other detectors.

When the crystal heats up and generates an electric charge, the gold is also used as an electrical conductor, carrying the signal to the detector’s amplifier and eliminating the need for separate electrical leads (which add bulk and weight).

The device can be made to identify “any specific range of electromagnetic frequencies” by altering the pattern and details of these gold layers – the inference being that the system could be tuned to specific gases or other substances.

“These designs allow this technology to be 10 to 100 times faster than existing detectors because the heat is created directly by the crystal” said Jon Suen, a postdoctoral

InnovOil

May 2017

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Left to right: A layer-by-layer look at the new metamaterial infrared detector, with simulated views as to its temperature distribution electric field, and how it absorbs power (below)

associate in Padilla’s laboratory. “This lets us create devices with fewer pixels and also presents the ability to sweep the detector across an area or capture images in motion.”

That gives the device an advantage over existing technologies. Its fast detection time

would allow it to scan an area quickly while looking for methane or natural gas leaks – either in a hand-held form or potentially mounted onto an aircraft or unmanned aerial vehicle (UAV). InnovOil would also imagine there

Bottom right (opporsite page): A prototype infrared detector made with the new metamaterial by SRICO

So far, SRICO has created a singlepixel prototype as a proof of concept, but it is now working to find funding from industry investors or grant to scale up and commercialise the technology.

The final form(s) of the sensor are unclear, but Padilla notes: “You could even make this into a low-cost lab instrument for spectroscopy for medical samples… I’m not sure what the eventual price point would be, but it’d be a lot less than the US$300,000 instrument we currently have in our laboratory.” n Web: ece.duke.edu / www.srico.com

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InnovOil

Cap-X technology helps reduce project costs

May 2017

Tim Skelton looks at the Statoil-backed Cap-X system, designed to usher in new subsea standardisation at the NOC’s Bauge and Njord fields

I

N March this year Statoil submitted its 20 billion kroner (US$2.3 billion) plan for developing the new Bauge field and rebooting the existing Njord field, both located in the Norwegian Sea. Speaking on behalf of project partners that include Engie E&P, DEA Norge and Faroe Petroleum, the company said a combination of operational efficiency improvements and new technology developments had helped shape the plan.

The most critical of these would appear to be the recently developed Cap-X system, which is designed to bring standardisation to the industry and is being put into use here for the first time.

Statoil’s original expectation for Njord was that it would have been scheduled for decommissioning in 2013. But thanks to operational efficiencies brought about by, among other things, greater co-operation between project partners and with suppliers, the new plan will now extend that field’s production life until around 2040.

In order to keep it operating efficiently and profitably for a further two decades, both the existing Njord A production platform and the Njord Bravo floating storage and offloading vessel (FSO) will be upgraded in order to increase recovery rates and extract more of the remaining resources from Njord, as well as from the nearby Hyme field. Between them these two fields are estimated still to contain around 175 million recoverable boe.

Work at Njord A will also facilitate the tie-back of the new Bauge field development, which is located just four km from Hyme and some 16 km northeast of the platform. The first proven reserves at Bauge were discovered in October 2013, and its recoverable resources have since been estimated to be around 73 million boe. The field development concept includes one subsea template, two oil producers and one water injector. Tying Bauge in to Njord A will itself increase the life of Njord by three years, the project partners say.

Cap-X The development at Bauge is significant, as it will see the first deployment of Statoil’s

Xxxxx

Jørgen Bratland and a Cap-X model. Picture: Statoil/Kjell Einar Ellingsen next-generation Cap-X subsea production technology, which it claims is cheaper both to produce and to install than other systems.

The technology was originally unveiled last year at the Barents Sea Conference. It builds on well-proven concepts by putting them together in new ways. Its most notable impact will be to reduce the subsea footprint by around 75%. Conventional templates have a footprint greater than 20m by 20m, but Cap-X works on an average area of around 10m by 10m.

The Cap-X seabed foundation uses a suction anchor technology that was originally developed jointly by Statoil, Royal Dutch Shell and the Norwegian Geotechnical Institute. The anchor is made from steel, with a fibreglass housing comprising a skirt and cap fixed on top. This superstructure then forms a compact protective casing capable of housing standard subsea equipment such as Christmas tree systems.

The casing has a streamlined square-based pyramidal shape that will, among other NEWSBASE

things, help to reduce the risk of potential damage caused by the snagging of trawler nets dragged by vessels passing on the surface.

Being only one-quarter the size of other subsea templates in current usage will enable more operations to be conducted from a mobile vessel instead of from a fixed rig, Statoil says. The longer-term plan is to use Cap-X as a practical solution for helping to commercialise potential resources in the Barents Sea, as well as in other areas that have shallow reservoirs. This initial rollout in the less harsh environment of the Norwegian Sea will help to prove its value in the field.

The new standard The ultimate goal is to bring about efficiencies, and hence improve profitability, by standardising all subsea structures. Statoil says the Cap-X housing can be produced more simply and in a shorter timeframe by many different suppliers, offering the potential for more efficient and more localised production at sites closer to the

May 2017

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Njord A platform Picture: Statoil/Thomas Sola

point of use. This combination of smaller size and reduced distances makes it more easily transportable, and moves much more of the installation process from rig to ship.

According to Cap-X inventor Kjell Einar Ellingsen, this will save rig days and marine installation costs, by facilitating faster operations and enabling the use of simpler vessels. The possibility of drilling single wells also allows for more flexibility in terms of seabed positioning, providing more optimal drainage of the reservoir, he told the Norwegian industry website petro.no.

Perhaps most importantly, at least as far as Statoil and its partner’s accountants will

be concerned, is that the company expects Cap-X’s design to cut overall costs by as much as 30% compared to conventional subsea installations. The part-state-owned oil major has called its design the “next generation of subsea solutions,” and says it brings the oil and gas industry a step closer to the ideal – and indeed long-promised – solution of “plug in and play” equipment for the seabed.

Both the rebooted Njord and Bauge developments are scheduled to come on stream at the end of 2020, and they will bring a welcome boost to the industry in midNorway and on the Norwegian Continental Shelf (NCS) as a whole. The decision to go NEWSBASE

ahead with the confidence of making both fields pay marks a refreshing change from recent years when new projects in the region have been squeezed by high up-front and operational costs.

The lessons learned can also be applied to other Statoil fields, which it hopes will herald the arrival of a new era of low-cost profitability. “With new technology, project improvements and close co-operation with the partners and supply industry, we now see opportunities to create considerable value for another 20 years,” executive vice president for Technology, Projects and Drilling Margareth Øvrum said in March. n

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Innovation Bangalore

InnovOil

May 2017

Shell opens new Indian technology centre to support East Asian operations

R

OYAL Dutch Shell has opened its newest technology centre, in Bangalore, India. The custombuilt 52-acre (21-hectare) site will support various internal and collaborative research and development projects to support the company’s operations across Asia.

Shell Technology Centre Bangalore (STCB) is the third such hub that the company has opened, following longestablished Technology R&D centres in Houston and Amsterdam. “These locations give us access to world-class researchers, working across time zones to ensure research never stops. These hubs can interlink through 3D virtual reality systems to work simultaneously on key projects,” a company spokesperson explained to InnovOil. The centre will house up to 1,500 staff, as well as laboratories and technology demonstration units. Shell says it will also host “a wide spectrum of technical disciplines and specific expertise in fields such as liquefied natural gas, subsurface modelling, data analysis, engineering design, bitumen, distillation and enhanced computational research.”

This includes collaborative R&D projects with universities, partners and research organisations, which Shell says can help to speed up the deployment of new technologies. Previous work has included research into chemistry and catalysis in partnership with the Indian Institutes of Technology, and collaboration with the Massachusetts Institute of Technology (MIT) on studies in advanced computing.

Shell also works with start-ups under its Make the Future accelerator programme.

Speaking after the opening, Shell Projects & Technology Director, Harry Brekelmans, said: “We consider R&D a fundamental part of Shell’s past and future success. Successful innovation, however, is more than just making balanced investments. Collaboration across different disciplines and with other

sectors externally is a key enabler of successful innovation. And collaboration is essential to meet our biggest challenge: timely development and deployment of the best and affordable energy solutions.

Our new Bangalore technology hub brings together the right people in a city that is synonymous with innovation.”

In particular, the STCB will support a number of major hydrocarbons operations in India itself, “including the core technical engine for Majnoon Iraq South Gas, upstream gas and LNG centre of expertise, FLNG support for Browse, the Abadi full-field development project, Sakhalin-2 integrated oil and gas project in Russia, full project support for Hazira capacity expansion and the Tabangao refinery LGP tank,” added the Shell spokesperson.

Waste not The centre is also helping to pioneer efforts to turn forestry, agricultural and municipal waste into transportation fuels, with a new demonstration plant being built at the site.

In particular, the STCB is home to a pioneering waste-to-fuel project (IH2). This NEWSBASE

is an advanced hydropyrolysis technology that uses catalytic processes known as hydrodeoxygenation and hydroconversion.

“It can convert virtually any type of nonfood lignocellulosic biomass and certain plastics directly into finished petrol, jet and diesel hydrocarbon fuels or blend stocks,” the company told InnovOil. “With appreciable amounts of nitrogen or sulphur present in biomass, [the remaining char] can be converted into ammonia and elemental sulphur fertilisers.”

“The centre is slated to play a prominent role in Shell India’s aspiration to custombuild a portfolio of new energy solutions specifically suited to India’s energy challenges. As this centre becomes fully functional and scales up, we hope to work on several more pioneering technologies that will contribute to India’s and the region’s sustainable energy future,” commented the chairman of Shell Companies in India, Nitin Prasad. n Contact: Cindy Lopez

Email: Cindy.Lopez@shell.com Web: www.shell.in

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page 32

May 2017

Oil industry turns Mark Boggett, managing director of the Seraphim Space Fund, the world’s first space-focused venture fund, talks to InnovOil about how space technology is changing and how new techniques are being applied to the energy industry

S

PACE may be the final frontier, but the availability of new technology much closer to Earth is having a profound effect on global industry.

Advances and cost reductions in components have meant that more satellite data can be collected and relayed than ever before. The advent of The Cloud and ondemand computing power also provides the necessary legwork to process that data into a usable, valuable form. With cheaper, better sensors and communications networks, that trend is only set to continue – and oil and gas exploration may be one of the greatest beneficiaries.

To learn more about what the impacts of such innovation may be, InnovOil spoke with the managing director of the world’s first venture fund focused on space technology.

Below, Seraphim’s Mark Boggett explains how technologies designed for the space industry, including imaging, robotics, AI and sensors, are now helping terrestrial operations.

NEWSBASE

How is space technology changing?

The space industry is undergoing an important period of change resulting in an increasing number of companies looking to apply space technology to other industries.

Costs have lowered significantly in the industry, which has led to lower data costs and therefore more data. Concurrently, there is a convergence of other technology that is making that data more actionable.

The satellite industry has traditionally produced satellites that cost between US$50 million and US$100 million to launch and weigh 3 tonnes. What’s happened in recent years is that entrepreneurs and outsiders from the space industry have started to identify that there are components that they can just buy off the shelf, many of which have been developed for the smartphone industry and that, by putting them together in an intelligent way, they can create satellites.

This means that satellites with much the same or better functionality can now be

May 2017

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page 33

to the final frontier produced for between US$25 and US$50 million dollars and they weigh only 100kg.

There are also a whole range of smaller satellites called nanosats which cost from US$100,000 to US$200,000 and weigh only 5kg. They can have good enough functionality for a whole range of centres.

Big space companies typically own small constellations of satellites because they’re so expensive. These satellites last from 10 to 15 years and therefore the technology gets antiquated pretty quickly.

What are the advantages of a smaller satellite?

Because these new satellites are smaller you can launch more of them – even in a single launch. That’s very much changing the market. Because costs are falling a lot of new entrants are coming into the market so non-traditional space companies are now competing with the traditional space companies.

You have a combination of smaller, lighter and cheaper satellites and falling costs to accessing space, meaning we are going through a period where a lot more satellites will be launched.

Those satellites are cheaper therefore the data that they can offer is at lower cost.

What will more satellites mean?

Because there are more satellites the revisit times that they go over any point of earth is increased dramatically to the point that you could almost get to a point of thinking about a real time solution.

Historically people had to rely on data that was months or years out of date – or if they were looking at something that was more frequent than that then probably 12 days would be a good revisit time – whereas now we are talking about multiple times in one day. In future that could become multiple times per hour.

NEWSBASE

How is this technology applied to the oil and gas sector?

One company that is using new and evolving smart image recognition techniques is called Terrabotics. They use 2D imagery from satellites to create 3D terrain data. The oil and gas industry would use this kind of data for pipe laying to understand what the terrain would look like, for instance, or for laying oil pipes in inhospitable areas The company is developing image processing, computer vision and geospatial algorithms and then transforming massive amounts of data – as in terabytes of data – from these satellites to turn them into valueadded data analytics products which they serve via software using Statistical Analysis System (SAS).

They’ve basically taken techniques that are used in the medical field – so in this instance it’s a technique that is used for enhancing MRI brain scans and then applied it to the satellite industry. They are able to infer data

page 34

from the 2D data that is presented so you end up with a series of images rather than a single image. This is where the multiple, bigger constellations of satellites really help. What they’re then able to do is derive sub-pixel level resolution from satellite imagery meaning they can provide rapid and automated results to create 3D terrain.

In this way, they are able to produce automated terrain maps within minutes that more traditional techniques used by the oil and gas industry would have taken weeks if not months to produce.

Another application for the same technology is to be able to look at changes over time – i.e. technology that can look at the same terrain data in 3D and then do an analysis to work out how that image has changed.

This could be used for mining, for instance, to look at an open-cast mine and then identify the volume of earth that has been moved and how it has moved. You

InnovOil

could use this technology to measure levels of production and so on.

It’s only just becoming available now because of several things happening at once: changes in satellite technology that is making them cheaper, more readily available and with higher revisit times; machine vision which is the sensor techniques that are collecting this data and then converting it into digital output – that’s really coming of age and it’s only really just happening now; and importantly, you’ve got parallel computing available in the cloud so any of these start ups can now access super computing power effectively by just tapping into the likes of Amazon. This means they can crunch a lot more data cost effectively and more quickly than they’ve ever been able to before.

What all this means is more much actionable intelligence. The world has really moved forward in the last year and that’s really going to accelerate how these areas are all coming together to create some actionable

Sentinel-1 was the European Space Agency’s first Earth observation satellite to be built for Europe’s Global Monitoring for Environment and Security programme. It is a polar-orbiting, all-weather, day-and-night radar imaging mission for land and ocean services. Picture: ESA NEWSBASE

May 2017

intelligence for different markets like oil and gas but also maritime, agriculture, insurance, hedge funds, smart surveillance and so on.

Many different industries use this kind of data.

What are other companies doing?

Another group of companies are really centring their work on using artificial intelligence – they use an algorithm to remove noise from satellite imagery and then on top of that, once they’ve cleaned the data, they then apply artificial intelligence methods to bring out the knowledge from the data.

Companies involved in that for the oil and gas industry are companies such as Orbital Insight and SpaceKnow. They are tracking trends through space and they provide analytics as a space product to the industry.

Then there’s another group of companies that are taking a different approach that are really using the low-cost nanosats to provide a different level of service. Low revisit time

InnovOil

May 2017

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“There is a huge pool of hundreds of businesses that are looking at ways of using this new low cost data” Mark Boggett, managing director of the Seraphim Space Fund

of imaging platforms has previously been a barrier, however these latest constellations of new satellites with their high revisit times makes the data much more useful. When multiple 20-plus files are available across a relatively short period of time over an area of interest this provides much higher granularity of change data that can be measured.

So some companies are using Synthetic Aperture Radar (SAR) sensors to do this – this is a very high quality technique where they can actually look through the crowds to give an image of the ground. There are lots of applications for oil and gas and military for using this type of sensor. Companies like Iceye or Geomatic Ventures are specifically start ups that are using SAR data to provide solutions to the oil and gas industry.

Then another group of companies that are using space-related knowledge to support the oil and gas industry are drone companies. As a fund we consider drones to be low flying satellites. They can effectively leverage all the

sensor technology and know how from the space industry to provide applications to the drone industry.

What do drones offer over satellites?

What’s really exciting about drones is that you can change the payloads, meaning that you can revisit the same areas multiple times even in a day, but you can do so even with different sensors. This is a really powerful way of being able to provide a multi-modal data fusion that can draw more information out of a data set.

A company called Sky Futures is one of the leaders in oil and gas inspections using drones. They already have many customers in the oil and gas market but are really only just starting to scratch the surface of what is available for the drones to be able to do.

We see very big opportunities for satellites and drones to be able to work together in harmony to provide different types of data sets that can be used by these data analytics companies to provide some very high quality

Terrabotics use 2D imagery from satellites to create 3D terrain data.

The oil and gas industry would use this kind of data for pipe laying in inhospitable areas.

Pictures: Tetrabotics

NEWSBASE

output. The oil and gas industry would be a big customer base for them.

How does the Seraphim Space Fund fit into all of this?

Our main focus as a fund is on identifying companies that use data drawn from satellites fused with terrestrial data, apply data analytics techniques and then add artificial intelligence, in order to provide useful actionable data for different industries.

Investors in the fund are big space companies like Airbus and Surrey Satellites.

They provide us with access to their resources to help evaluate proposals we get.

We also have a strategic partnership with the European Space Agency.

There is a huge pool of hundreds of businesses that are looking at ways of using this new low cost data to provide applications to various markets from insurance to oil and gas, the internet of things, smart cities and intelligent transport. n

page 36

InnovOil

May 2017

NEWS IN BRIEF

Sirius signs up Tidewater equipment for Ororo work Sirius Petroleum has signed up with Tidewater Marine International to provide offshore service vehicles (OSVs) at Nigeria’s Ororo field. Sirius announced the deal on April 13, marking another step towards the launching of an exploration programme at the field.

Tidewater Marine International is a wholly owned subsidiary of Tidewater, working in Nigeria as a technical partner with T1 Marine Services.

UK-listed Sirius is serving as technical and financing partner for oil and gas projects in Nigeria. Its current focus is on the shallowwater Ororo field, where Guarantee Petroleum holds 55% equity interest and Owana Oil & Gas holds the remaining 45%. The company has lined up contracts with China Oilfield Services Limited (COSL), Schlumberger and ADD Energy for work on the project, with drilling planned to start in the first half of this year. In March, Sirius contracted Polaris Consulting to undertake a seabed survey on Ororo prior to rig mobilisation by COSL Drilling Pan-Pacific.

Schlumberger will provide integrated services management for the drilling programme. The partners in Ororo plan to drill three wells and install wellhead platforms. Sirius raised cash in February through the issue of shares, in order to cover the cost of deposits for equipment and

items with long lead times such as wellheads, christmas tree piping and valve systems.

The Ororo field is located in Oil Mining Licence (OM L) 95 in the northwestern area of the Niger Delta. Much of the area is operated

by Chevron, which discovered the Ororo field in 1986. The field is offshore Ondo State and is in water depths of seven to eight metres. Sirius obtained a three-year extension of its licence for the area from Nigeria’s Federal Ministry of Petroleum Resources in July 2016.

Earlier this month Sirius announced the appointment of a new chief operating officer, Peter Gregory, who will be responsible for operations in the Ororo field.

Edited by Ed Reed edreed@newsbase.com

Mitsui ultralarge container vessel plans approved DNV GL has issued an Approval In Principle (AIP) to MOL and Samsung Heavy Industries for the future design of a series of four LNGpowered 20,000 TEU containerships, which have been under construction.

MOL signed a deal for the series of containerships with SHI in 2015. The ships were designed in anticipation of using LNG as a fuel, in light of more stringent environmental regulations that will take effect in the years to

NEWSBASE

come. At the construction stage, MOL and SHI developed a basic plan targeting vessels in service, performance evaluation, compliance with new regulations, and risk assessment (Hazard Identification Study [HAZID])in a joint study, and completed the basic design in March.

Global regulations on exhaust emissions from merchant vessels, not only by the International Maritime Organization (IMO) and other specialized international bodies, but also by countries all over the world are becoming tighter. MOL have proceeded studies on the use of LNG fuel in light of growing demand for next-generation clean fuels to replace conventional heavy fuel oil, because LNG can significantly reduce emissions of CO2, a major contributor to global warming, as well as NOX and SOX, which cause acid rain and other problems.

MOL

JFE wins Soma LNG expansion deal JFE Engineering, the engineering arm of major Japanese steelmaker JFE Steel, has won a contract to expand the regasification capacity of the Soma LNG import terminal in Fukushima Prefecture.

JFE Engineering was awarded the contract

by Fukushima Gas Power (FGP), a joint venture led by Japan Petroleum Exploration (JAPEX) and which involves four other companies, JFE Engineering said last week, without disclosing the value of the deal.

JAPEX, Mitsui & Co., Osaka Gas, Mitsubishi Gas Chemical and Hokkaido Electric Power own 33%, 29%, 20%, 9% and 9% of FGP respectively.

Under the contract, JFE Engineering will build a vaporiser and related facilities to boost the Soma LNG terminal’s regasification capacity.

These facilities are scheduled to come on stream in the spring of 2020, the Tokyo-based company said.

FGP plans to launch construction work on a 118-MW natural gas-fired combined cycle power plant at a site adjacent to the still under construction Soma LNG terminal this summer.

The power plant project also involves the construction of a new – and second – LNG tank with a storage capacity of 230,000 cubic metres at the terminal. The Fukushima power plant is scheduled to start commercial operations in the spring of 2020. A consortium of Japanese heavy

May 2017

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NEWS IN BRIEF

The aproved development of Statoil’s Trestakk discovery

machinery maker IHI and construction firm Shimizu has already won a contract to build the second tank.

JAPEX launched construction work on the terminal, the first such facility in Fukushima Prefecture, in November 2014. The terminal’s first LNG tank will also have a storage capacity of 230,000 cubic metres. JAPEX is also building a 40-km gas pipeline between the Soma LNG terminal and Iwanuma City, Miyagi Prefecture.

In April 2015, JFE Engineering won a contract to build the 33-km section of the new gas pipeline in Miyagi Prefecture.

JAPEX plans to complete the terminal and the new pipeline in December and put them into operation in March 2018.

The Niigata-Sendai Line of JAPEX’s domestic gas pipeline network runs between the Port of Niigata Higashi, Niigata Prefecture, on the Sea of Japan coast and Sendai City, Miyagi Prefecture, on the Pacific coast via Iwanuma City.

Edited by Andrew Kemp andrew.kemp@newsbase.com

Green light for Trestakk The Norwegian Petroleum Ministry has given Statoil the go-ahead to develop its Trestakk discovery. The ministry approved the Plan for Development and Operation (PDO) that was submitted by the company on behalf of the licence partners in late 2016. Owing to cost and efficiency improvements, Statoil also said the

investment costs would be little more than half its original calculation.

Located on the Halten Bank in the Norwegian Sea, around 20 km southeast of the producing Asgard field, Trestakk was discovered in 1986. The medium pressure and temperature reservoir lies almost 4,000 metres below the surface, in water depths of around 300 metres.

Its estimated recoverable resource volumes have been put at 76 million boe, mainly in the form of oil with some associated gas. This is more than it was initially thought to contain.

The field will be developed using five subsea wells, including three production wells and two gas injection wells. These will be tied back into the Asgard A floating production, storage and offloading (FPSO) vessel, which lies 25 km to the northwest.

Trestakk is expected to start up production in 2019, once production drilling and modification work – scheduled for 2018 – is completed. Asgard A will also undergo modification, as it will require a new flexible riser and associated subsea structures.

The life expectancy of Trestakk is around 13 years, and it is expected to help maintain profitable operation of Asgard A at least until 2030. The upgrades made to the FPSO should also enable improved recovery volumes from the original Asgard field, Statoil claimed.

Moreover, the company also said it was able to lower its original investment estimate from 10 billion kroner (US$1.16 billion) to around 5.5 billion (US$637 million). The reductions were based on “simplification and optimised scope,” as well as ongoing efficiency improvements, it said.

NEWSBASE

“This is a good example of what we are able to achieve in collaboration with our licence partners and suppliers by innovative thinking, and spending enough time on maturing the best concept choice,” Torger Rød, Statoil’s head of project development, said in a statement.

Statoil operates Trestakk with a 59.1% ownership stake, alongside licence partners ExxonMobil E&P Norway (33%) and Eni Norge (7.9 %).

Edited by Ryan Stevenson ryans@newsbase.com

Trelleborg provides buoyancy to ROV SuBastian Trelleborg’s has engineered and manufactured a custom syntactic foam buoyancy package for the Schmidt Ocean Institute for use on its new Remotely Operated Vehicle (ROV), SuBastian.

The Schmidt Ocean Institute underwater robotic research program includes the design and development of a 4,500 meter robotic vehicle for use on research vessel Falkor. The ROV is outfitted with a suite of sensors and scientific equipment to support data and sample collection, as well as interactive research, experimentation, and technology development.

The buoyancy package on SuBastian is made from Trelleborg’s Eccofloat TG30, a high performance syntactic foam.

page 38

InnovOil

May 2017

NEWS IN BRIEF

several new facilities, including a pressurised bulk filling plant for light petroleum products, a 4,000 tpy sulphur production unit and other associated plant infrastructure.

China Petroleum Engineering and Construction Corp. (CPECC), a subsidiary of China National Petroleum Corp. (CNPC), served as the general contractor for the first phase of the modernisation programme.

It made use of refining technologies and equipment from a number of foreign and local suppliers, including CPE of China, Universal Oil Products (UOP) of the US, Technip of France and Kazgiproneftetrans of Kazakhstan.

According to the document, the upgrade will help Kazakhstan reduce emissions and remain in compliance with the technical requirements of the Customs Union. It will also allow the Shymkent refinery to produce an additional 460,000 tpy (10,700 bpd) of high-octane gasoline, 226,000 tpy (4,640 bpd) of diesel and 27,000 tpy (590 bpd) of jet fuel.

Bob Kelly, Managing Director within Trelleborg’s applied technologies operation, says: “One of the challenges with deep water syntactic foam is producing the lightest possible foam for a given depth which translates into maximum uplift or buoyancy for the vehicle. A high strength to weight ratio means our customers get the industry’s maximum uplift or buoyancy per cubic foot, allowing them to design their vehicle with a lower volume buoyancy package, reducing costs and improving vehicle performance and handling.”

“We were able to create the precise buoyancy package needed for SuBastian, ensuring success for the future commercialization of this project.

The unique customizable design coupled with the selection of Trelleborg’s proven Eccofloat material will provide many years of service with the flexibility to adapt to all future equipment and mission requirements.”

The SuBastain ROV is designed to go to depths of 4,500 meters/ 2.8 miles, which is deeper than the average ocean depth of 3,700 meters / 2.3 miles. Trelleborg’s Eccofloat TG30 is designed for a service depth of 5,000 meters / 3.1 miles. The ROV will be suitable to support high resolution seafloor mapping, photomosaicing, video and image gathering, and collections of rocks, animals, and seawater samples. It is equipped with a versatile array of power and data interfaces to enable integration of a wide range of add-on deep sea instruments and samplers that oceanographers may need to support their deep sea research.

TRELLEBORG

First-stage modernisation at Shymkent refinery completed THE Shymkent oil refinery in southern Kazakhstan has wrapped up work on the first stage of its modernisation programme.

The plant’s management team recently signed a document attesting to the completion of the project, according to the Astana Times. In the document, managers noted that the process of commissioning new equipment was under way and would be completed in July. They also stated that the refinery was now capable of producing high-quality gasoline and diesel fuel that met K4 and K5 environmental standards, which are in line with Euro-4 and Euro-5 specifications.

The project included the overhaul of the plant’s largest facility, an isomerisation unit that turns out light gasoline fractions, via the installation of an associated unit for the preliminary hydrotreatment of raw materials.

As a result of this work, the unit will be able to turn out motor gasoline with higher octane levels and lower benzene content.

Meanwhile, the document said, the overhaul also encompassed the reconstruction of the Shymkent refinery’s diesel hydrotreatment plant. It also involved the construction of NEWSBASE

Edited by Joe Murphy josephm@newsbase.com

KOC tenders major pipeline jobs KUWAIT Oil Co. (KOC) is awaiting bids for several major contracts to install new oil and gas pipelines. The move is part of ongoing efforts to improve the country’s production, transportation and export infrastructure as a corollary to ongoing upstream and downstream development.

The company, the domestic upstream operating subsidiary of state-owned Kuwait Petroleum Corp. (KPC), continues to chase the increasingly improbable target of raising daily output by 500,000 bpd by the end of the decade.

Far from being discouraged by the oversupply forcing current global production cuts, it appears to be taking advantage of the enforced pause at some fields in order to accelerate such work.

Meanwhile, the protracted process of selecting a contractor for the new crude pipeline to feed the greenfield refinery now finally under construction in the south took a fresh turn – in the form of a long-anticipated retender.

The bulk of KOC’s planned capacity hike from the current 3.1 million bpd to 3.65 million bpd by the end of the decade is due to be delivered through increasing production at the northern fields – from around 700,000 bpd to 1 million bpd.

May 2017

InnovOil

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NEWS IN BRIEF

The US$4.2 billion main engineering, procurement and construction (EPC) contract on the crucial upstream project to develop heavy oil reserves from the Lower Fars reservoir at the Ratqa field was finally awarded to the UK’s Petrofac in early 2015.

KOC has since been working to expand and upgrade the northern production, processing and export infrastructure to cope with the envisaged increment – awarding contracts over the past two years for the construction of three new gathering centres (GCs) and various water treatment and injection facilities.

A tender – anticipated for five years – was finally floated in March to install a 48-inch (1,219-mm) crude pipeline parallel and as a standby to the existing line delivering oil from the northern fields to the Central Mixing Manifold and onwards to the North and South tank farms at Al-Ahmadi port for export.

Bids are due by June 4 from a shortlist of companies comprising: Norway’s Aker Kvaerner; China Petroleum Jilin Chemical Engineering & Construction; Chiyoda and JGC, both of Japan; Athens-based Consolidated Contractors Co. (CCC); Daewoo Engineering & Construction (E&C), GS E&C, Hyundai Heavy Industries, Samsung and SK E&C, all of South Korea; the US’ KBR; India’s Larsen & Toubro (L&T); Germany’s Lurgi; Petrofac; Italy’s Saipem; Canada’s SNC Lavalin and Spain’s Tecnicas Reunidas (TR).

The proposed line would have capacity of 1 million bpd and would interface with facilities being installed as part of Petrofac’s Lower Fars project. Bids are due by June 18 for a longdelayed contract now finally retendered by KOC to install 350 km of pipelines carrying heavy crude and gas further south from Al-Ahmadi to feed the 615,000 bpd new refinery planned at Al-Zour in the extreme south-east.

Victory cements the British stalwart’s centrality to Kuwait’s capacity expansion ambitions. These were most importantly manifested in a multi-billion dollar job nearing completion to carry out the first phase of a landmark heavy oil project at the northern fields, which are envisaged as being the other main source of KOC’s output hike. KOC is the domestic upstream operating subsidiary of state conglomerate Kuwait Petroleum Corp. (KPC).

Petrofac was announced on March 28 as the winner of the US$1.3 billion engineering, procurement and construction (EPC) contract to install so-called Gathering Centre 32 (GC32) at Burgan – a maturing 79-year-old field that is the source of more than half of national production of around 3.1 million bpd.

The UK firm emerged as the lowest bidder

for the much-anticipated deal following the submission of prices in January – undercutting bids of US$1.4 billion and US$1.5 billion from South Korea’s SK Engineering & Construction and Samsung Engineering respectively, with bids also opened from Daewoo, also South Korean, Italy’s Saipem and Spain’s Tecnicas Reunidas.

The UK’s Amec Foster Wheeler completed the front-end engineering and design (FEED) contract in 2014 and the reasons for the hiatus are unknown. However, the pause coincided with the oil price slump from the middle of that year and with enforced ramp-ups in output from KOC’s fields to compensate for the cessation of production by fellow KPC subsidiary Kuwait Gulf Oil from the Partitioned Neutral Zone shared with Saudi Arabia.

Meanwhile, the reactivation of the contracting process came shortly after the UK’s BP signed a new five-year enhanced technical services agreement with KOC covering development work at Burgan.

The new GC, to be located 53 km south of Kuwait City, is designed to separate sour oil and gas from the Arifjan, Marat, Minagish-Oolite and Burgan Wara areas of the field from sweeter streams and will have capacity to process 400,000 bpd of liquids into 120,000 bpd of crude, 95.4 mmcf (2.7 mcm) per day of gas and 280,000 bpd of water.

Edited by Ian Simm ians@newsbase.com

Enterprise announces NGL pipeline project

Edited by Ian Simm ians@newsbase.com

Midstream infrastructure firm Enterprise Products Partners announced on April 10 that it had started building an NGL pipeline from the Permian Basin to its fractionation and storage complex at Mont Belvieu, Texas.

The 571-mile (919-km), 24-inch (610-mm) Shin Oak pipeline will initially carry up to 250,000 bpd of NGLs from the company’s Hobbs fractionation and storage facility in Texas’ Gaines County. The pipeline will have the capacity to be expanded to 600,000 bpd at a later date, Enterprise said. The company said that the Shin Oak pipeline would also provide takeaway capacity for mixed NGLs extracted at gas processing plants in the Permian region.

This includes two Enterprise facilities that began service in 2016 and the Orla I plant that is scheduled to begin operations in the second quarter of 2018.

Petrofac wins crucial Burgan contract PETROFAC has been awarded a contract to install a new gathering centre at the super-giant Burgan field in southeast Kuwait by Kuwait Oil Co. (KOC).

The facility will be the first to process sour crude from the field and is an important component in the firm’s plans to raise production by more than 500,000 bpd by the end of the decade.

NEWSBASE

InnovOil

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May 2017

NEWS IN BRIEF

Enterprise’s facility at Mont Belvieu is the largest of its kind in the world, according to the company, with underground storage capacity of about 130 million barrels and NGL fractionation capacity of roughly 670,000 bpd.

A ninth fractionator is under construction at the complex and will add 85,000 bpd of fractionation capacity when it comes online, which is anticipated in the second quarter of 2018.

Shin Oak is expected to start up by the second quarter of 2019. Enterprise said the pipeline was already supported by long-term customer commitments.

The company noted that the Mont Belvieu complex was already connected by pipeline to both the US Gulf Coast and Enterprise’s LPG and ethane export terminals on the Houston Ship Channel.

“The Shin Oak pipeline project is part of Enterprise’s larger plans in the Permian to leverage our integrated midstream assets to link supplies of cost-advantaged US hydrocarbons to the largest domestic and global NGL markets,” the CEO of Enterprise’s general partner, Jim Teague, said. “This additional pipeline takeaway capacity to Mont Belvieu will provide Permian producers the flow assurance they need to continue the unfettered development of their reserves with confidence.”

Edited by Anna Kachkova annak@newsbase.com

Fluor to tackle Cassia FEED Fluor Corporation was selected by BP Trinidad and Tobago (BP) to perform the front-end engineering and design (FEED) for the Cassia Compression Project off the east coast of Trinidad and Tobago. Fluor booked the undisclosed contract value into backlog in the first quarter of 2017.

Fluor’s scope includes the design of a new offshore gas compression platform, new connecting bridge and modifications to the existing Cassia hub. The platform will compress gas produced from the existing Cassia platforms.

“Fluor has 50 years of experience developing some of the world’s most complex offshore projects, including several BP facilities in Trinidad and Tobago,” said Mark Fields, president of Fluor’s Energy & Chemicals business in the Americas. “In addition, our Stork division currently provides maintenance, modification and asset integrity services to BP’s offshore assets there. With a focus on

maximizing local content, we will deliver a safe, reliable and capital efficient solution to BP.” “As the project advances, Fluor will use its integrated solution model to support the project,” said John Harrower, executive director of offshore operations for Fluor. “Benefits of this model include an improved design through fabrication and maintenance team engagement in the design process, reduced costs through the global sourcing of major equipment and improved execution through Fluor and Stork’s extensive in-country experience and use of local resources.”

FEED activities are expected to be completed in 2017 with first gas expected in 2020.

FLUOR

Statoil awards Transocean two rig contracts Statoil and license partners have decided to use the semisubmersible rig Transocean Spitsbergen on three exploration wells in the UK, and then on a six-well production drilling campaign on the Aasta Hansteen licence in Norway.

The exploration drilling campaign in the UK will be conducted for the Mariner, Jock Scott and Verbier licenses, and is planned to start in the summer.

The contract value for the three fixed wells is estimated at around 18 million USD, which includes integrated drilling services such as fuel, casing running, ROV, slop treatment and

cuttings handling.

“We believe that the UK Continental Shelf (UKCS) still presents exciting opportunities.

Securing this rig will enable us to fulfil our exploration ambitions of testing potential along the underexplored margins and more mature areas of the basin, in addition to near-field potential at Mariner. This year will see our most active exploration campaign for Statoil in the UK since repositioning in 2011 and we look forward to testing our three diverse prospects,” says Jenny Morris, vice president Exploration UK. Mariner is one of the largest projects currently under development in the UKCS. Recoverable reserves from the initial development are estimated at 250 million barrels of oil excluding near field exploration potential. The topsides modules will be installed in the Mariner field this summer. First oil is expected in 2018.

The drilling campaign on Aasta Hansteen is planned to start towards the end of 2017 or the beginning of 2018. The contract value for six fixed wells is estimated at around 95 million USD, which includes integrated drilling services such as fuel, casing running, ROV, slop treatment and cuttings handling, plus mobilisation-, demobilisation and modification costs.

The gas field will be developed with a Spar FPSO platform, as the first on the Norwegian Continental Shelf and the largest in the world.

The hull and platform deck will be assembled in Stord this year, and the platform will be towed to the Norwegian Sea next year. n STATOIL

From left: Ian Paterson (Transocean Drilling UK Ltd), Rannfrid Skjervold (Statoil ASA) and Karl-Erik Johannessen (Transocean Norway Operations AS). (Photo: Kjetil Eide) NEWSBASE

May 2017

InnovOil

What next …?

To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections

If Chart Industries’ innovative solutions could help your gas or LNG operations, please contact Joris van Kreij on +31 657 884 215 or email joris.vankreij@chartindustries.com For enquiries regarding Wärtsilä’s jettyless LNG transfer system, please contact Kenneth Engblom on +358 40 756 6686, or via kenneth.engblom@wartsila.com INTECSEA believes that its Low-Motion FPSO concept could enable dramatic reductions in development costs.

To get in contact with the company for more information call +1 (0)281 987 0800 or email info.USA@intecsea.com If DSME and DNV GL’s post-Panamax LNG carrier design is of interest to you, contact Nikos Späth at Nikos.Spaeth@dnvgl.com, or visit www.dsme.co.kr For more information or enquiries regarding Duke University’s collaboration on a metamaterials gas sensor, visit ece.duke.edu or www.srico.com To enquire about the newly opened Shell Technology Centre Bangalore, speak with Cindy Lopez on Cindy.Lopez@shell.com

NEWSBASE

page 41

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“We were pleased with the immediate interest that our on article Kongsberg attracted.”

Page 14

“The article Oxford Catalysts Group Maritime’s Munin AUV is excellent”

Mark Hampton, Manager of Exploration and Technology, Shell Exploration and Production Inc. Published by

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