InnovOil Issue 54 July 2017 by NewsBase Ltd.

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Bringing you the latest innovations in exploration, production and refining Issue 54

IN THE DRINK

The AUV battery that runs on seawater Page 6

HYDROGEN BOMBSHELLS Innovations transforming clean fuel Page 13-21

READY FOR THE SEA FLOOR NOV’s subsea storage units Page 24

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Inside A note from the Editor

Battery AUVs

Open Water Power is developing a new aluminium-based battery

Contacts:

Preventing bacteria growth 8

Media Director Ryan Stevenson ryans@newsbase.com

Laser-induced graphene fights bacteria

A matter of degrees

Media Sales

LumaSense temperature measurement

Tech radar

Charles Villiers charlesv@newsbase.com

Outside the world of oil and gas

HYDROGEN 13-21

Kevin John kevinj@newsbase.com

Ultra-efficient electrolyser 14

Editor Andrew Dykes andrewd@newsbase.com

Nel Hydrogen on Norway’s hydrogen history

Chalmers’ fuel cell catalyst 18 A yttrium-platinum nano-alloy ten times as effective as pure platinum

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CSIRO membrane

NPD pushes EOR

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Vanadium alloy in hydrogen separation

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Norway considers the use of EOR technologies to bolster production

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

NOV stores crude, water and chemicals

BP backs artificial intelligence

Exxon’s algal biofuel yield 27 Increasing lipid production to 40%

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ction ations in exploration, produ Bringing you the latest innov

Gathering no MOSS

Rocket science

North Sea loan scheme

Methane hydrates

News in brief

KHI’s non-spherical LNG tanks

and refining July 2017

Issue 54

K IN THE DRINthat runs on seawater The AUV battery Page 6

BSHELLS HYDROGEN BOM rming clean fuel

NASA know-how is helping oil and gas

Innovations transfo Page 14-21

Rival companies slow rate of job losses

China hypes it up but Japan leads

R THE SEA FLOOR READY FOstor age units NOV’s subsea Page 24

Contacts 40 NEWSBASE

VAxplorer Extreme torques, extended reach

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A note from the Editor “HYDROGEN is the fuel of the future, and always will be” – or so the adage goes. It is a fairly common belief, and not without reason. Much of the economics and efficiencies around hydrogen are tough to make the fuel work in commercial settings, and given that much of the hydrogen used commercially is still derived from methane steam reformation, a highly CO2-intensive process, its claim to cleanliness is sometimes undermined. However, the market is growing. In the transport sector, competition between hydrogen fuel cell vehicles, electric vehicles and the internal combustion engine has never been fiercer. Cheaper renewable power coupled with new equipment and an industry now willing to push ambitious decarbonisation plans has sparked renewed interest in hydrogen technologies – and oil and gas should take note. This is not simply a case of self-preservation, but of new opportunity. Who better to design, refine and implement the infrastructure and production facilities than the industry already adept at storing, shipping and refining hydrocarbons? As the debate over transport fuels continues, the solutions found now are likely to set the agenda for the next fifty years or more. In this month’s issue we take a closer look at the technological vanguard of the new hydrogen economy. Nel Hydrogen talks with us about its ultra-efficient alkaline electrolyser, and how the company is intertwined with the heritage and history of hydrogen production in Norway. Meanwhile, Australia’s CSIRO is developing

a membrane separator for splitting ammonia directly into hydrogen, opening up a new potential avenue for hydrogen storage and transport. One of the project’s architects, Dr Michael Dolan, explains more inside. In addition, Chalmers University of Denmark is using nanoalloys to improve the effectiveness of platinum catalysts, with a view to lowering the cost of fuel cells significantly. Outside the hydrogen economy, other storage media are also available. In particular, this month we look at a new aluminium battery being developed by Open Water Power. The company is hopeful that its system could enable a tenfold increase in the operable range of unmanned underwater vehicles (UUVs). We also speak with NOV subsea engineers regarding its subsea storage unit (SSU), a new approach to storing crude, produced water or chemicals on the seafloor, and one which could enable cost and capex reductions on a range of greenfield and brownfield projects, as well as aiding EOR programmes. That could be particularly useful, given recent statements by Norway’s NPD. The regulator has suggested that it could force operators to implement EOR programmes from the beginning of field life as it pushes to maximise recovery across the NCS. Callum Cyrus looks at the options available, and where they might be implemented. All this, as well as BP’s new foray into artificial intelligence, a graphene innovation for zapping bacteria, methane hydrate breakthroughs and much more. We are pleased to present the July issue of InnovOil.

Andrew Dykes Editor

NEWSBASE

InnovOil

Battery AUVs head page 6

July 2017

Open Water Power is developing a new aluminium-based battery that uses water itself as a power source. It believes the technology could offer a tenfold increase in AUV range

NDERWATER vehicles are taking on more tasks than ever, but power facilities and mission requirements still tend to separate them into two broad camps: tethered remotely operated vehicles (ROVs) and battery-powered autonomous underwater vehicles (AUVs). Much of this has to do with battery capacities. Drones capable of travelling great distances unassisted will typically require low-power components, while available power can also restrict the amount of tasks it can perform. While large AUVs have impressive endurance – Kongsberg Maritime’s HUGIN, for example, can travel for 100 hours at 4 knots – bigger batteries will be needed as more tasks are handed to robots. It is here that li-ion technology begins to slow down. At these size requirements, it often is not safe or practical to transport large battery packs. They cannot be transported by air, for example, and to work at any kind of depth they also require housing in some form of pressure vessels. The solution, as MIT spin-off Open Water Power sees it, is to use a battery that runs on seawater itself. Using patent-pending aluminium alloy cell chemistry, the company says it can offer a tenfold increase in the range of so-called unpiloted underwater vehicles (UUVs), compared to the use of traditional li-ion batteries. Water, water everywhere The system consists of an activated aluminium anode – an alloy that also contains small amounts of other non-toxic metals – an aqueous alkaline electrolyte and a hydrogen evolving cathode. Sea water is pulled into the battery, and is split at the cathode into hydroxide anions and hydrogen gas. The hydroxide anions interact with the aluminium anode, creating aluminium hydroxide and releasing electrons. Those electrons travel back toward the cathode, transferring energy to a circuit along the way – essentially splitting the process into two half-reactions, creating a fuel cell. OWP says the chemistry achieves an

Another reason for its effectiveness is the systems’ ability to use produced hydrogen as a means of maintaining neutrally buoyancy. This, OWP says, offers a lower and therefore better density at all depths, compared with syntactic foams and alternative gases. “Furthermore, our chemistry’s continuous production of hydrogen at negligible gauge pressure allows us to control buoyancy dynamically using only lightweight bladders and plumbing, turning UUVs equipped with our power systems into powerful hybrid gliders,” OWP says. OWP cell components optimal total efficiency of about 33%, and produces only aluminium hydroxide and hydrogen gas as harmless waste. According to calculations provide by the company, around 20mg per minute of aluminium and 40mg per minute of water will produce 1W of power, along with 2W of heat, 2 mg hydrogen and 58 mg of aluminium hydroxide. In terms of energy density, the system offers somewhere between 2.1-5.5kWh per litre, far above more hazardous li-ion options. On dry land, the system is inert and the battery only activates when flooded with water, meaning it could be flown out to offshore missions if necessary. In addition, once the interior aluminium corrodes, it can be replaced at a fractional cost. OWP notes that the anode only reacts significantly in the presence of its electrolyte, and does not risk run-away even under the most severe conditions, including a system puncture or an internal short circuit. Moreover, depending on the mission, the alloy itself can be tailored to fit the specific power and lifetime requirements. An internal pump also circulates the electrolyte, pushing aluminium hydroxide from the anode and onto a custom precipitation trap. When saturated, the waste traps are ejected and replaced automatically. Meanwhile, the electrolyte itself prevents marine organisms from forming inside the power system. NEWSBASE

Naval gazing OWP is currently working with the US Navy to replace batteries in acoustic sensors designed to detect enemy submarines. In vehicle applications, it hopes that the battery technology will allow AUVs to run for considerably greater times and distances. Where current systems can patrol pipelines and assets a few dozen miles from base before returning, the company believes that its chemistry will enable missions hundreds of miles out to sea. This summer, the company plans to launch a pilot with Riptide Autonomous Solutions, which will use the battery systems in AUVs performing underwater surveys. Riptide’s current models can travel roughly 100 nautical miles (185 km) in one go, but OWP is looking to increase that distance to 1,000 nautical miles (1,850 km). Where typical AUV battery life might be 24 hours, or less in deepwater missions, OWP’s chemistry could extend that to a month. From an oil and gas perspective this is significant: the ability to monitor pipelines or subsea assets externally, or collect environmental data, for example, without a manned mission offshore represents an immediate saving of thousands of dollars. With greater power output and lifespan also comes greater flexibility – UUVs could carry some form of manipulator function, enabling them to perform automatic or guided interventions when necessary. Speaking with MIT News, co-inventor Ian Salmon McKay drew on the example

InnovOil

for Open Water July 2017

page 7

posed by Malaysia Airlines’ missing airliner: “In looking for the debris, a sizeable amount of the power budget for missions like that is used descending to depth and ascending back to the surface, so their working time on the sea floor is very limited.” he said. “Our power system will improve on that.” OWP holds a contract with the Department of Defense to develop power systems for portable AUVs and a separate signing for sea-floor based power systems. However, it is upfront about some military and energy applications remaining offlimits: “We are not a good fit for extremely high sustained power-density systems like torpedoes, nor are we a good fit, because of our water-based chemistry, for high temperature applications like downhole drilling. But if your application requires longduration, moderate power underwater, our chemistry’s performance is the best in class.” With trials ongoing, interest in the battery system is sure to be high. So far, it has run larger cells for a week, and smaller, low-power cells for a month, but the next step will be integrating the technology into a fully functioning system. OWP itself pegs its cell technology at TRL level 6, and battery systems at level 4, but there already look to be plenty of applications where further refinements could help develop a final product – in particular UUVs, ocean-floor sensors and sonobuoys, it says. That scale-up could come quickly. In May, OWP was acquired by L3 Technologies, a technology provider for comms and sensor systems for military applications. Oil and gas will perhaps be slower to follow the military’s lead, but marine engineering firms should be quick to jump on the possibilities, if OWP’s technology can be incorporated into their own. “We have great confidence – and the data to back it up – that this technology is the future of underwater power,” OWP says on its website – and it might just be right. n

Projected operable area for UUVs with OWP cells

Contact: Open Water Power

Email: info@OpenWaterPower.com Web: openwaterpower.com

Cells assembled into battery system NEWSBASE

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InnovOil

Notorious LIG helps prevent bacteria growth

July 2017

Experiments using laser-induced graphene have shown it to be an effective solution for fighting bacteria, and may be of particular interest to the oil and gas industry

NOTHER week, another newfound application for graphene: in this case, the material in question is in fact laser-induced graphene (LIG), a material similar to the ubiquitous singlelayer carbon sheet but which also possesses sponge-like qualities. LIG was first developed in 2014 by Rice University chemist James Tour, arguably the father of modern nanotechnology. Experiments in his lab successfully burned part of the way through a sheet of polyimide with a laser, turning the surface into a lattice of interconnected graphene sheets. The material has even been touted as a possible energy storage solution as a potential replacement for supercapacitors, and even batteries. Researchers have since suggested applications in wearable electronics and fuel cells, as well as for superhydrophobic or superhydrophilic surfaces. Most recently, however, LIG has been used as part of an effective anti-bacterial treatment method, having been shown to protect surfaces from biofouling in water. According to a paper published by scientists at Rice University, Texas and Ben-Gurion University of the Negev (BGU), when electrified, LIG can even be used to “zap” bacteria. Bugging out The antibacterial properties of graphene have long been discussed; however, this research goes some way towards proving and quantifying to what extent this occurs. The team has also proved that the effect is magnified dramatically when a voltage is applied across the material. The paper, led by BGU postdoc fellow Swatantra Singh and Rice grad student Yilun Liare, and co-authored by BGU’s Senior Lecturer Avraham Be’er and Emeritus Professor Yoram Oren, describes applying varying voltages between 1.1-2.5V, during which the LIG electrodes biocidal effects were “greatly enhanced.” As Rice notes in its statement, it transforms LIG into “the

LIG

Polymide

A sheet of polyimide burned on the left to leave laser-induced graphene shows the graphene surface nearly free of growth. Picture: Arnusch Lab/BGU bacterial equivalent of a backyard bug zapper.” In an experiment, fluorescently tagged pseudomonas aeruginosa bacteria were deposited in a solution with LIG electrodes above 1.1V. Viewing the process under a microscope, the team observed the bacteria being drawn toward the anode, and above 1.5V, the cells began to disappear, vanishing completely within 30 seconds. At 2.5V, bacteria disappeared almost completely from the surface after one second. Rice then partnered with Professor Christopher Arnusch, a lecturer at the BGU Zuckerberg Institute for Water Research and who specialises in water purification. Arnusch lab-tested LIG electrodes in a bacteria-laden solution with 10% secondary treated wastewater and found that after nine hours at 2.5V, 99.9% of bacteria were killed and the electrodes strongly resisted biofilm formation. The exact cause of the bacterial removal is unknown, but the team suspects a combination of factors. Primarily, the sharp edges of the graphene surface are thought to pierce and destroy the bacterial membranes, but in addition to the electrical voltage itself, the researchers also observed localised electrochemical generation of hydrogen peroxide – an effective biocide. In their paper abstract, the authors note: NEWSBASE

“The bacterial killing mechanism depended strongly on the physical and electrical contact of the bacterial cells to the surfaces.” Moreover, LIG’s anti-fouling properties also prevent dead bacteria from accumulating on the surface, Tour said. “The combination of passive biofouling inhibition and active voltage-induced microbial removal will likely make this a highly sought-after material for inhibiting the growth of troublesome natural fouling that plagues many industries,” Tour said, specifically referencing “places like watertreatment plants, oil-drilling operations, hospitals and ocean applications like underwater pipes that are sensitive to fouling.” In emailed comments to InnovOil, Tour confirmed that commercial deployment of the LIG system could be done via a polymer film applied physically within the areas to be protected. Moreover, he said, LIG is not an overly expensive material; it can be produced with commercial plastics and electricity, all in air and at room temperature. All this could make it a very viable solution for the prevention of biofilm growth in the oilfield – bacteria beware. n Contact: Tour Group, Rice University Email: tour@rice.edu Web: www.jmtour.com

July 2017

InnovOil

A matter of degrees

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LumaSense Technologiesâ&#x20AC;&#x2122; E2T product manager, David Ducharme, explains why accurate temperature measurement is critical in a modified Claus sulphur reactor

HERE are two critical temperatures required for the safe and efficient operation of a sulphur furnace. The first is the refractory temperature, which is critical for hightemperature alarms and automated shutdown systems in the furnace. This measurement represents the infrastructure temperature, for which high temperature limits are specified by the engineering design. However, using only refractory measurements for furnace control offers no early warning of high-temperature excursions. The second is the gas temperature, aka the combustion or flame temperatures. Measurement of this temperature offers the operator process temperature information and an early warning of temperature excursions before they are absorbed by the refractory and trigger alarms or shutdowns. The ability to measure combustion temperature accurately provides an early warning of critical temperature events that are crucial for controlling the furnace in the higher operating temperatures found in an oxygen-enriched environment. Thermal event timeline High-temperature thermal events begin with a rise in the flame or gas temperature. The energy from the flame is absorbed by the refractory, causing an increase in its temperature over time and eventually reaching the high-temperature alarm or system-shutdown limits. It is therefore best practice to use gas or flame temperature measurements for process control together with a refractory measurement for safety systems. Yet typical industrial pyrometers only measure single temperatures and are subject to flame transparency changes in the furnace as feed changes accrue. Operators can therefore spend considerable capital on multiple units, yet fail to guarantee an accurate reading for their asset. Flame transparency Single wavelength measurements are more prone to errors when measuring flame (Gas)

or thru-flame (refractory). When clean burning, the flame can become partially transparent to the gas wavelength being used. This transparency will allow some of the cooler refractory to be seen and the refractory temperature to be included into the pyrometer measurement, resulting in a lower measurement for the gas temperature than is actually occurring. In the case of a dirty or larger flame, the refractory wavelength measurement will pick up elements of the flame temperature as a result of low flame transparency. In this case, this will add components of the flame temperature to the refractory measurement, producing a higher refractory measurement than is actually occurring. The issue is exacerbated by the changing flame transparency as feedstocks change over time, creating a variable error in a typical single wavelength pyrometer. Both of the above errors can be eliminated by using a single two-wavelength pyrometer that contains separate refractory and gas (flame/combustion) detectors and filters. NEWSBASE

Two measurements, one system The LumaSense Pulsar 4 combines the two wavelengths for refractory and gas measurements in a single pyrometer, reducing the cost of installation and maintenance. The benefit of having a single pyrometer with two separate detectors filtered for refractory and gas measurements is the ability to apply flame transparency algorithms to the output to reduce flame impingement on refractory measurements and flame transparency in the gas combustion measurements. Using the information obtained from the refractory measurement and the gas flame/combustion measurement, and then applying the proprietary LumaSense Flame Measurement Algorithm (FMA), flame transparency errors can be removed and corrected in the refractory and gas measurement outputs of the pyrometer. In practice, this results in more accurate measurement for furnace operations, greater advanced warning of any high-temperature events and reduced maintenance and installation costs. n Contact: LumaSense Technologies Tel: +49 69 973 730 Email: info@lumasenseinc.com Web: www.lumasenseinc.com

InnovOil

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July 2017

On the radar

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

Wet paint

Elastic fantastic

A joint project between Yanshan University and the Carnegie Institution for Science has produced a new form of ultra-strong, lightweight carbon. The material is also elastic and electrically conductive, opening up a wealth of applications in anything from aerospace to electrical engineering. It was created by pressurising and heating a structurally disordered form of carbon called glassy carbon. This material was brought to about 250,000 times normal atmospheric pressure and heated to approximately 1,800°F (982°C) to create the new strong and elastic carbon. The result was a substance with both flexible graphite-like bonding and ultra-hard diamond-like bonding, giving rise to the unique combination of properties. Under the high-pressure conditions, disordered layers within the glassy carbon buckle, merge and connect in a number of ways. This process creates an overall structure

that lacks a long-range spatial order, but has a short-range spatial organisation on the nanometre scale. Scientists had previously tried subjecting glassy carbon to high pressures at both room temperature (referred to as cold compression) and extremely high temperatures; however, the former material could not maintain its structure when brought back to ambient pressure. “Light materials with high strength and robust elasticity like this are very desirable for applications where weight savings are of the utmost importance, even more than material cost,” former Carnegie fellow and current Yanshan University Professor Zhisheng Zhao remarked. “What’s more, we believe that this synthesis method could be honed to create other extraordinary forms of carbon and entirely different classes of materials.” Their group’s findings were recently published in Science Advances. n NEWSBASE

A team at RMIT University has developed a “solar paint” capable of both absorbing water vapour and splitting it to generate hydrogen. The material contains a new compound – synthetic molybdenum-sulphide – that acts much like silica gel, the moisture-absorbing compound used to keep various consumer products fresh and dry. However, it also acts as a semi-conductor, catalysing the splitting of water atoms into hydrogen and oxygen. Central to the process is titanium oxide, the ultra-white pigment used in various paints and other white-coloured products. RMIT lead researcher Dr Torben Daeneke explained: “We found that mixing the compound with titanium oxide particles leads to a sunlightabsorbing paint that produces hydrogen fuel from solar energy and moist air… The simple addition of the new material can convert a brick wall into energy harvesting and fuel production real estate.” The team believes that the material could be used to coat a variety of surfaces, including buildings or infrastructure, to generate hydrogen. The catalyst itself is formulated as an ink that can be coated onto insulating substrates, such as glass, they note in the abstract to their paper Surface Water Dependent Properties of Sulfur Rich Molybdenum Sulphides – Electrolyteless Gas Phase Water Splitting,” published in the ACS Nano journal. “Our new development has a big range of advantages,” Daeneke said. “There’s no need for clean or filtered water to feed the system. Any place that has water vapour in the air, even remote areas far from water, can produce fuel.” Co-author, distinguished Professor Kourosh Kalantar-zadeh noted: “This system can also be used in very dry but hot climates near oceans. The sea water is evaporated by the hot sunlight and the vapour can then be absorbed to produce fuel.” It is unclear at this stage how the gas may be collected or stored from the paint; however, as the demand and applications for hydrogen increase, the technology may catch the interest of new developers. n

July 2017

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Tiny robots to inspect Fukushima Japanese engineering giant Toshiba, together with the International Research Institute for Nuclear Decommissioning (IRID), has developed a new micro-ROV for use inspections at the Fukushima Daiichi Nuclear Power Station Unit 3. At only 13cm in diameter, it is small enough to enter and inspect the damaged primary containment vessel (PCV) of the damaged reactor. In October 2015 a survey by Tokyo Electric Power Co. (TEPCO) found the PCV of Unit 3 flooded with coolant to a depth of about 6m. In determining how to best advance the plant’s clean-up, fuel and other debris submerged in the coolant must be located and mapped. However, the penetration hole giving access to the PCV is

only 14cm in diameter, limiting the size of any robot that could be deployed. In response Toshiba and IRID have created a small, radiation-hardened robot. At 13cm wide by 30cm long it is compact, but provides a platform for front and rearfacing video cameras and LED lights. The robot is powered and remotely controlled via wire, and operators can control its progress through the coolant and the PCV with five thrusters, four rear-mounted and front-mounted. It will deliver a video feed that will clarify damage to the PCV interior and information

on how best to retrieve fuel debris. Toshiba’s Nuclear Energy Systems & Services general manager Goro Yanase noted: “In this case, we had to meet the specific challenges of limited access and flooding, in a highly radioactive environment. Working with IRID, we succeeded in developing a small robot with high level radiation resistance, and through its deployment we expect to get information that will support the advance of decommissioning.” According to the two groups, the robot will be deployed this summer, following the training of operators. n

Brittle by little A steel-focused workgroup at the UK’s University of Warwick (WMG) has developed a new processing system, enabling low density steel-based alloys to be produced with maximum strength, whilst remaining durable and flexible. Until now, the group says, the process had been “largely impossible.” Two lightweight steels were tested – Fe-15Mn-10Al-0.8C-5Ni and Fe-15Mn10Al-0.8C – for their potential to achieve maximum strength and ductility. During production, two brittle phases can occur in these steels – kappa-carbide (k-carbide) and B2 intermetallic. These phases make the steels hard but can limit their ductility, making the resulting alloy difficult to roll. WMG researchers found that at certain high annealing temperatures, these brittle phases can become much more controllable, NEWSBASE

allowing the steels to retain their ductility. Between 900°C to 1,200°C, the k-carbide phase can be removed from production. Similarly, the B2 intermetallic brittle phase can become more manageable, forming in a disk-like, nano-sized morphology, as opposed to a coarser product which forms at lower temperatures. Current processes for strengthening lightweight steels make them less but the research, led by WMG’s Dr Alireza Rahnama, goes some way towards mitigating the problem. The breakthrough could help produce safer and light parts for cars, and other equipment, by enabling manufacturers to make more streamlined parts. “Alloys with higher strength and ductility could alleviate some of these concerns by reducing weight and improving energy efficiency. Lightweight steels are one of the candidates to address these concerns,” Dr Rahnama noted. n

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HYDROGEN

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SPECIAL SUPPLEMENT Pages 13-21

HIGHWAY TO NEL

Hydrogen innovation from Norway Page 14

CATALYTIC CONVERSIONS

SANE IN THE MEMBRANE

How a new alloy could slash platinum use

CSIROâ&#x20AC;&#x2122;s new approach to hydrogen storage

Page 18

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InnovOil

July 2017

Nel and high water: the ultra-efficient electrolyser HYDROGEN

Nel Hydrogen claims to have the most reliable and efficient electrolysers in the world, and it may soon be taking the fight to the hydrocarbons industry. Andrew Dykes reports from Notodden

ARGE-SCALE, affordable production of hydrogen is often thought of as a futuristic blueprint for the energy industry, but this belies the success Norway has had with the technology for the past century. Ninety years on, the latest incarnation of one of the founding partners in the country’s heavy water industry is still innovating. Nel Hydrogen’s roots go back to 1927, to the wave of industrialisation which swept Norway after the formation of Norsk Hydro and the development of the country’s extensive hydropower resources. Hydro built an industry on a new, revolutionary process to create ammonia-based fertilisers by fixing nitrogen from the air – the Birkeland-Eyde process – and using power from hydro dams built at Svelgfossen and later Rjukan (the latter made famous through its heavy water manufacturing during World War 2). That particular year saw the more efficient Haber-Bosch process perfected and adopted in Norway via a partnership with Germany’s IG Farben. Hydro would go on to build the world’s largest electrolyser plants in world, breaking its own records on multiple occasions from the 1930s to the 1950s. This pedigree still has influence on Nel today. Having been part of the hydrogen business combined under the short-lived StatoilHydro merger, the company was then spun out, before investors launched a public offering in 2014. Nel now designs and delivers technology to produce, store and distribute hydrogen, with a particular focus on using renewable energy. Its business units cover electrolyser systems, refuelling stations for hydrogen vehicles and a range of other hydrogen infrastructure projects such as energy storage or gas-to-power. The company’s VP of market development and public relations, Bjørn Simonsen, explained to InnovOil how the company’s history had helped maintain its position at the forefront of the technology.

Top of the range Nel markets its alkaline water electrolyser systems as “the most reliable and efficient in the world.” Electrolysers themselves are a choice between the large-scale A-Range and the compact C-Range, depending on the application and the amount of product required. These produce 99.9% pure hydrogen with cost efficiencies approaching natural gas-based methods. “When they built these large electrolyser plants in the 1930s and 1950s, they wanted them to be as efficient as possible. They put a lot of effort and R&D into exactly that. NEWSBASE

What they developed was an active layer that we coat the electrodes with,” Simonsen explained. Yet unlike most innovations covered by InnovOil, the key to this superior performance is not a patented process. “The recipe for this has never been patented; it’s a trade secret and it has been with the company for several decades.” That said, it does not seem to have affected the company’s performance. “Noone else has been able to beat that, even until now,” Simonsen said. A-Range units are supplied in a number

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HYDROGEN Below: A-Range electrolyser

Above: NorskHydro fertiliser factory in Notodden

of sizes, from the A-150 which will produce 50-150 cubic metres hydrogen per hour, to the A-485, capable of 300-485 cubic metres. All use a 25% aqueous solution of potassium hydroxide electrolyte, produce hydrogen at atmospheric pressure and operate at 80°C. PLC control systems mean the systems work unattended, and can be linked to the existing plant controls. Power consumption is where Nel technology excels. Regardless of size, the cell stack requires 3.8-4.4kWh of DC power per cubic metre of gas produced. 0.9 litres of feed water are required per cubic metre. Automation also means the systems are low-

maintenance, the only expected work being cell stack replacement, which usually occurs after 8-10 years in operation. All in all, Nel says this enables the A-Range to provide “the lowest operational costs available.” The C-Range works within largely the same parameters but with a compact design for reduced footprint – the smaller C-150 unit fits into two 12m x 2.9m x 3.6m containers, just bigger than an average 40ft (12.2-metre) shipping container, and has an outlet pressure of 30 or 200 bar, depending on customer configuration. Where A-Range units may be used for large-scale production, typical C-Range applications include hydrogen fuelling stations and the redistribution of hydrogen by industrial gas companies. NEWSBASE

Highway to Nel Although typical customers may come from the heavy industry, plastics manufacturing and technology sectors, Nel is also gaining ground in territory once reserved for pure hydrocarbons. A new framework agreement signed in mid-June is evident of the momentum behind hydrogen as a greener option in supplementing gas supplies. As part of a contract worth over 3 billion kroner (US$350 million), Nel will supply electrolysers to French company H2V Product, in support of an industrial powerto-gas programme. H2V intends to inject hydrogen as a substitute for natural gas into its gas pipelines at its terminals in Northern France. The framework agreement outlines an initial procurement of a 100-MW hydrogen plant for completion between 2018 and 2020, and the supply of a further six plants during 2020-2025. With a total of 700 MW, Nel CEO Jon André Løkke called it the “largest industrial-scale power-to-gas project ever seen.” Keen to capitalise on the growth in the sector, as well as completing the technology offering, Nel has also extended its reach through some high-profile acquisitions. Complementing the company’s history with alkaline atmospheric electrolysers, in February it took on US-based Proton OnSite, the largest proton-exchange membrane

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InnovOil

July 2017

HYDROGEN

C-Range arranged in large-scale plant

(PEM) electrolyser supplier in the world. “By acquiring them we are now the largest player in the market,” Simonsen confirmed. This will help to fuel North American expansion, where interest in infrastructure to support fuel cell electric vehicles (FCEVs) is growing too, particularly on the West Coast. “We’re very excited to begin delivering hydrogen fuelling stations to Shell in California in the near future, and we are also looking at sites for establishing renewable hydrogen production to fuel the vehicles,” he explained. Scaling up Greater interest, a healthy order book and new innovation are all driving prices down too. Most notably, Simonsen said that cost parity with electrolysed hydrogen was approaching parity with that of natural gas. For industrial consumers, that could be a major breakthrough. “As we come to a lower cost on the unit, and which we have demonstrated recently, we are gradually becoming more and more

competitive with steam methane reforming (SMR) on a capex level. With the decrease on electricity prices – also renewable – we see that in some regions we can compete with SMR today without subsidies,” he said. Economies of scale are still crucial – competition relies on large plants – but the trend is undeniable. “For the time being a large-scale plant of 200-400 MW [in] scale, we estimate a capex level of US$450 per kW. This at least will compete with medium-scale reformers.” A report from the US’ National Renewable Energy Laboratory (NREL) estimated the 2020 costs of an SMR plant at around US$7,300 per kg of H2 production per day, based on a total plant capacity of 100 kg per day. Economies of scale bring this down even further, but support Simonsen’s assertion that Nel can more than compete in the mid-scale range. This is pushing a new debate in Europe with refiners and other users, especially NEWSBASE

those who are keen to reduce their carbon footprint. “It’s a renewable benefit that we can bring primarily. For refiners, it can potentially lower the carbon footprint of the fuels,” he explained. “You have two options to make the fuel cleaner: you can mix biofuels at the end of the process or you can switch fossil-based hydrogen with renewable hydrogen within the process itself. That’s what we will be proposing to refineries. We are in dialogue with several refineries in Europe and there are also ongoing processes in the EU on how to better integrate renewable hydrogen into regulations for renewable fuel policy.” SMR remains the dominant mode of hydrogen production for now, but it is a market ripe for disruption. The next few years could see big changes afoot as supply and consumption patterns change. That much of that momentum could be driven by a renewable technology pioneered almost a century ago should be a great credit to its Norwegian innovators. n Contact: Bjorn Simonsen

Email: bjorn.simonsen@nelhydrogen.com Web: http://nelhydrogen.comv

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InnovOil

page 18

Chalmers finds more effective fuel cell catalyst

July 2017

HYDROGEN Nano-alloys of platinum (grey) and yttrium (blue) are created using sputtering in a vacuum chamber. This is done by directing plasma (purple) at a piece of platinum with small attached pieces of yttrium. The nanometre-thin alloy films effectively transform oxygen (red) and protons (white) into water

A yttrium-platinum nanoalloy has been shown to be ten times as effective as pure platinum in a fuel cell

HALMERS University of Technology and Technical University of Denmark have been investigating replacement materials for platinum catalysts in fuel cells to reduce the need for the expensive element. New research into nanoalloys has shown that it is possible to reduce the platinum requirement significantly, and that the new technology is also well suited for mass production. In this case, yttrium was bonded with the traditional platinum catalyst to create an alloy more effective than the single element alone. “A nano-solution is needed to mass-produce resource-efficient catalysts for fuel cells. With our method, only one tenth as much platinum is needed for the most demanding reactions. This can reduce the amount of platinum required for a fuel cell by about 70%”, says Björn Wickman, an Assistant Professor at the Department of Physics at Chalmers University of Technology. Speaking to by email, Wickman explained why the new material had proved to be more effective. “The Pt3Y alloy has the property that the oxygen reduction reaction (ORR) is much more efficient here than on pure Pt. The specific activity (surface activity) of Pt3Y is about a factor of seven higher than for pure Pt.”

In a fuel cell, he said, the most important figure is the mass activity – the current generated per mass of catalyst. “What we have done in this study is to present a method that can produce the Pt3Y as a nanomaterial, which is absolutely necessary in order to reach high mass activities. We show that our nanofilms of Pt3Y have a mass activity up to 10 times higher than nanoparticles of pure platinum. That means that if our material can be introduced in a real fuel cell only one tenth of the amount of the element would be needed on the cathode side, where the ORR takes place.” If this level of efficiency can be achieved in a functional fuel cell, they could be produced using about as much platinum as an ordinary car catalytic converter. With platinum selling for around US$30 per gram and with 30-40 grams needed in a typical fuel cell, the solution could save as much as US$1,000 per unit, and help to push fuel cell vehicles to a cost-competitive target of around US$30 per kW of capacity. Alloyed forces Previous research has proved that it is possible to mix platinum with other metals – in this case yttrium – to reduce the amount needed to produce a functional fuel cell. Yet no one has yet managed to create alloys NEWSBASE

with these metals in nanoparticle form in a manner that would be suitable for largescale production. The biggest barrier to this is that yttrium tends to oxidise instead of forming an alloy with the platinum. Chalmers researchers have overcome this problem by combining the metals in a vacuum chamber, using a deposition technique called sputtering – where a mass of yttrium is bombarded with ions, causing it to eject particles which then bond with the platinum. The result is a nanometre-thin film of the new alloy that allows mass-produced platinum and yttrium fuel cell catalysts.

InnovOil

July 2017

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HYDROGEN Pure platinum with thin fixed foils of yttrium have been used to create the new nano-alloys

According to an abstract of the team’s paper, published in the Advanced Materials Interfaces journal: “The films show an improvement in stability over the same materials in nanoparticulate form. Physical characterisation shows that the thin films form a platinum overlayer supported on an underlying alloy. The high activity is likely related to compressive strain in that overlayer.”

The successful demonstration of the technique is a major part of the team’s breakthrough. Traditionally, deposition of catalysts is done via a wet chemical method, but “in our case,” Wickman said, “There is no functioning wet chemical method to produce Pt3Y nanoparticles, despite much work during the past 10 years.” They are also confident that the technique would be scalable to larger production volumes, although it would be more costly. Yet with the prospect of only using a tenth NEWSBASE

as much platinum, he believes the more expensive fabrication method could be justified. Wickman says the next steps will be to test these catalysts in real cells. This will require some slight modification to the design of the fuel cell itself, largely because current electrodes produced using the chemical deposition method would not be reproducible using the sputtering technique. “This might, however, not be as difficult as one might think,” he explained. “There has been a lot of research into alternative electrode designs – for example electrodes typically referred to as nanostructured thin films (NSTF). These have been identified as promising for future fuel cells and a large amount of research is now devoted to developing them. Most NSTF designs would be well suited to combine with sputtering to deposit the catalyst material.” Commercial platinum-catalysed PEM fuel cells may have been around for over 60 years, but more innovation will be needed if they are to make it in mass-market applications. Nanoalloys such as these are but one step on the road to a hydrogen future. n Contact: Björn Wickman

Tel: +46 31 772 51 79 Email: bjorn.wickman@chalmers.se Web: www.chalmers.se

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InnovOil

July 2017

New fame for CSIRO membrane HYDROGEN

A vanadium alloy membrane is tipped to transform the hydrogen separation process, and enable the use of ammonia as a means of carrying the ultralight element. Andrew Dykes speaks with the CSIRO team to learn more

YDROGEN production should not be of interest to oil and gas operators purely for its role in creating other products. With the so-called hydrogen economy expected to grow, refiners, gas transport fleets and many other hydrocarbon-based businesses stand to gain from the substantial opportunities. In particular, the transport of hydrogen has proved to be a difficult problem to solve. Although gaseous hydrogen can be transported by pipeline, it has a tendency to damage steel, and needs considerable pipe wall thickness to ensure it does not escape. The US Department of Energy (DoE) notes in a briefing on the fuel that “the high initial capital costs of new pipeline construction constitute a major barrier to expanding hydrogen pipeline delivery infrastructure.” It is for that reason that InnovOil took notice of a new project led by Australia’s Commonwealth Scientific and Industrial Research Organisation (CSIRO). Under a new two-year project announced in May 2017, a research group will work to develop and demonstrate a hydrogen production system that can deliver at least 5kg per day of high-purity hydrogen, directly from ammonia. This somewhat inverts the conventional wisdom on ammonia production – hydrogen, usually derived from natural gases, is typically combined with nitrogen to produce ammonia for fertiliser – but the logic is sound. Ammonia (NH3) has a high capacity for storing hydrogen atoms – 17.6% by weight, and at a volumetric density 45% greater than liquid H2. It has often been proposed as a carrier method, given that it is stable and can be stored in pressure tanks in much the same way as propane or other fuels. Cracking it also produces nitrogen – a non-toxic, non-greenhouse gas (GHG). Yet the large amount of energy needed to

create and/or separate ammonia molecules and unfavourable economics has discounted any further practical use – until now. Ain’t got that swing A technique called pressure swing absorption (PSA) is the benchmark for hydrogen purification, and delivers H2 pure enough for use in proton exchange membrane (PEM) fuel cells. Yet PSA systems are bulky, have a large number of moving parts, and as a batch process, require duplication of all components to enable continuous production. The key to the CSIRO project rests in a different approach based on a proprietary membrane separator technology designed by Dr Michael Dolan. The thin metal membrane allows hydrogen to pass while blocking all other gases, and using decomposed ammonia feedstock, enables H2 conversion in a single step. Moreover, unlike a PSA system, it permits a smaller plant – with no moving parts – to work in continuous operations. The membrane is made of a vanadiumbased alloy. Dolan explained more about it to InnovOil via email: “Our design philosophy has been to use inexpensive materials and mass-production techniques (like metal tube extrusion and electroplating) as much as possible. The membrane substrate itself is a dense tube of a permeable, inexpensive [vanadium] alloy which is drawn down to a wall thickness of ~0.2 mm, and diameter of 10 mm. A catalytic layer is then deposited on the inner and outer surfaces.” The membrane separates gaseous molecules at temperatures of 300-400˚C. Ammonia is first vaporised, then passed over a catalyst which decomposes it into nitrogen and hydrogen. The gas is pressurised through the membrane to extract high-purity H2 from the mixture. There is of course an efficiency penalty NEWSBASE

for this; the system requires heat to drive the endothermic decomposition process, and the loss of pressure means the hydrogen must then be fed into a compressor for use in fuel cell applications (although it could be used at ambient pressures in stationary power generation). Dolan added: “As with most gas separation processes, the recovery of the valuable product (H2) is never 100%. We will typically operate with around 85% recovery, but this depends on residence time and desired output.” That said, there are methods of improving its efficiency. “The unrecovered energy will not be wasted. The off-gas, which contains mostly nitrogen (N2) with unrecovered H2 and unreacted NH3, can be combusted to create the heat required for ammonia decomposition, or it can be fed to a second device, like a high-temperature fuel cell, internal combustion engine or turbine for power generation,” Dolan confirmed. Selling out the palladium Overall, CSIRO is confident that this membrane will enable it to produce a separation system at a lower cost than the

July 2017

InnovOil

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HYDROGEN

Decomposed ammonia passes through CSIRO’s metal membrane to produce pure hydrogen

competing palladium-based membrane technology in use today. By how much lower, Dolan said, would be difficult to confirm at this stage, but that the issue was much more about performance and purity. “It really depends on the geometry of the palladium [Pd] membranes and the intended application. PEM fuel cells require H2 which contains no more than 100 ppbv of ammonia. Even very small defects in a membrane will mean this limit is exceeded, and the fuel won’t be suitable for use in a PEM fuel cell.” “Our membranes are thicker (200 micrometres) than the supported Pd-based membranes which are being commercialised elsewhere (< 10 micrometres),” This thickness of the vanadium membrane eliminates the potential for defects, meaning the CSIRO system can meet the required PEM purity standard. “Thinner membranes are more susceptible to defects, either during fabrication, or over time. The likelihood of these defects can be mitigated by making thicker membranes, but the high cost of Pd (currently US$28,000 per kg) makes this cost-prohibitive,” he added.”

Its main benefit will be in unlocking existing infrastructure for hydrogen export and transport. CSIRO’s goal is to enable the membrane technology to fill the gap between hydrogen production, distribution and delivery. Separator systems would be deployed in the form of a modular, scalable unit that can be used at, or near, a refuelling station or production site. “Because membranes are a modular technology, the scale-up issues are minimised. To make more H2 we just put more membrane tubes into the plant,” Dolan said. Having begun the two-year endeavour, Dolan and his team are now working on the first 5kg per day demonstrator plant. “This plant will also include compression, and the resulting H2 will be distributed to several FCEV manufacturers for demonstration in their vehicles,” he said. The project has received a A$1.7 million (US$1.3 million) grant from Australia’s Science and Industry Endowment Fund (SIEF), which will be matched by CSIRO, as well as some highprofile public support from the likes of industry members such as BOC, Hyundai, Toyota and Renewable Hydrogen. NEWSBASE

Once this first project is complete, Dolan and the team have their eyes on wider commercialisation. “We’ll then be looking to undertake trials in Korea and Europe at larger scales, probably around 100 kg per day,” he said. From here, the only limit would appear to be which sources of energy are most useful to hydrogen production. CSIRO has said it will investigate all stages of the technology chain, from solar photovoltaics (PV), concentrated solar power (CSP), through to grid management, water electrolysis and ammonia synthesis to identify the best way forward. CSIRO chief executive Dr Larry Marshall stated: “This is a watershed moment for energy, and we look forward to applying CSIRO innovation to enable this exciting renewably sourced fuel and energy storage medium a smoother path to market.” The oil and gas industry too is now waking up to the potential of hydrogen as a commercial opportunity, and investment in technologies such as CSIRO’s now will play a key role in the development of a supporting economy. Dolan believes the change is already visible; “Renewable H2 will become more important in the longer term, and most of the major established oil and gas companies have already announced major investment and partnerships to facilitate this transition… Using ammonia as a hydrogen carrier is one of the greatest emerging opportunities.” n Contact: Dr Michael Dolan

Tel: +61 733 274 126 Email: michael.dolan@csiro.au Web: www.csiro.au/

InnovOil

NPD pushes EOR

page 22

The Norwegian regulator is considering forcing the use of EOR technologies to bolster production across the NCS. Callum Cyrus reports on the potential options

S maximising production and recovery become an even greater priority in the North and Norwegian Seas, regulators are pushing technology adoption even harder. The Norwegian Petroleum Directorate (NPD) now hopes to encourage more operators to use enhanced oil recovery (EOR) techniques at new-build projects as well as fields nearing the end of their productive lifespan, Reuters reported on June 15. More than that, firms could even be ordered to do so as part of their plans for development and operations (PDOs), an approach which would echo NPD efforts to encourage joint infrastructure programmes between upstream projects. It is understood that Statoil’s Johan Sverdrup could trial EOR technology when it launches in late-2019, piloting an injection scheme which would mix injected water with polymers to bolster recovery. Statoil had touted a lower break-even cost for Johan Sverdrup of US$25 per barrel, after last year reducing its full project budget estimate by as much as 23%, to around 140-170 billion kroner (US$16.4-19.9 billion). But whether operators will welcome such interventions remains uncertain. Declining production Norwegian oil production plummeted from a peak of roughly 3.11 million bpd to 1.62 million bpd in 2016, though last year’s figure was itself an improvement on the 1.57 million bpd reported for 2015. Meanwhile, the crash in crude prices has forced Norwegian operators to make savings at their development projects to maintain profitability. According to the Norwegian Oil & Gas Association, upstream spends could slide by 7% this year to 143 billion kroner (US$16.7 billion), before falling further to 131 billion kroner (US$15.46 billion) in 2018. The upshot of this has left the NPD searching for ways to ensure that operators squeeze the most efficiency out of each NCS project, both on expenditure and in terms of reserves. In mid-June, the NPD said that fully utilising EOR technologies could lift the NCS’ recovery factor by around 7% of inplace oil reserves. On the basis of Norway’s 27 largest oilfields, the directorate estimates that an additional 3.7 billion barrels could be unlocked with EOR. It goes so far as to argue NEWSBASE

July 2017

that failing to invest in EOR would result in half of Norway’s oil resource being left below ground. “The NPD believes that it is worthwhile to investigate whether some of this technical potential can be realised. Full scale pilots are needed to quantify the resource potentials of EOR,” the directorate told Newsbase Intelligence (NBI). Already, EOR has prolonged the lifespan of major Norwegian producing fields by 12 years on average when compared with the original PDOs. But the NPD wants to extend this further, by encouraging operators to implement EOR techniques at the beginning of each lifecycle. Some believe this would allow EOR to improve recovery rates of the so-called “easy oil” at fresh developments, rather than focusing on the more challenging task of lifting recovery volumes at the end of life, which are more challenging for displacing agents to shift. Weighing the options On the one hand, the NPD’s emphasis on early-stage EOR investment makes sense given the planning needed to make recovery upgrades efficient. The NPD said: “There are reasons to believe that early commitments to infrastructure, weight and spare capacity could open up future EOR projects.” In an economic assessment of EOR published in 2015, senior advisors from Petoro estimated that retrofitting Norwegian fields with a 15,000 cubic metre low salinity water injection (LSWI) plant could cost US$300 million. Further hurdles arise when considering that injection wells must be adequately sited into the aquifer, Petoro said, which could open a wide gap between injection and production wells. This could prolong the time required to gather testing results, which would in turn reduce net present value (NPV) projects for EOR investments at existing reservoirs. Petoro suggested these challenges might be bypassed by using EOR in undeveloped sectors instead. Yet the NPD was less clear on how it proposes to convince operators to bear EOR investments at the beginning of NCS projects. While it could certainly make it a licensing requirement to do so, investors may be displeased with racking up additional short-run costs at a time when slashing

July 2017

InnovOil

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Field development plan for Gullfaks A. Pictures: Statoil

Project in the Norwegian North Sea from January 2021. WAG interchanges between the injection of water and gas to increase the volume of the reservoir brushed by injected fluids. Statoil will spend around 22-25 billion kroner (US$2-5.3 billion) on the upgrades between 2018 and 2024, to extract an additional 190 million barrels of oil reserves. The so-called “Increased Oil Recovery (IOR)” programme will comprise six templates, each of which can hold up to four wells connected to the Snorre A platform. At present, Statoil proposes completing 11 production wells and 11 WAG wells for the expansion project, of which four should be pre-drilled before launch in 2021. Its concept would see up to 2,000 cubic metres of gas per day received from Gullfaks A, as pressure support between 2022 and 2036, but Statoil has said this could change depending on market prices for gas.

capital expenditure has been a priority. The NPD said: “[Our] role is to make sure that all economic resources are produced from the reservoirs. NPD encourages the companies to investigate and pursue all possibilities to achieve this, including EOR technologies.” Choices, choices Then there is the question of which technology would be most cost-effective in Norwegian waters. EOR is typically more expensive when deployed at offshore fields, where all of Norway’s producing fields are currently situated. According to a University of Aberdeen paper published in November 2014, it would have cost GBP338 million (US$430 million) at 2014 prices to develop EOR for 42 million barrels of oil reserves in the UK Continental Shelf (UKCS). Lifecycle operating costs were estimated at another GBP100 million (US$127 million). This largely remains the case regardless of whether operators choose polymer or gas injection strategies for their EOR projects. Polymer flooding programmes were judged to require a high initial investment, much of which would be spent modifying the FPSO or platform to accept polymer throughput.

The cost of purchasing polymers was said to account for 80-90% of total opex projections, and there is also the risk that polymer will degrade in the choke of the reservoir. However, polymer EOR schemes are believed to bolster extraction at “modest” levels for a “very long time”, which could make it more suited for Johan Sverdrup at the beginning of its lifecycle. Moreover, it may be easier for the NPD to convince investors to roll out polymer injection prior to the FID stage, before any key design decisions have been taken and approved. Gas injection may also involve “very large” operating costs because of the gas volumes needed over an EOR project’s lifecycle, according to the University of Aberdeen. At 2014 prices, the paper estimated using gas injection to extract 53.3 million boe would cost GBP503.5 million (US$641 million) to develop, plus GBP 1.492 billion (US$1.9 billion) for gas supplies. But gas injection may bring other advantages for developers on the NCS, particularly given the supply glut which sent prices crashing in 2015. Statoil is already preparing to utilise water alternating gas (WAG) injection at its Snorre Expansion NEWSBASE

What next? In NBI’s view, the NPD is likely to select a handful of Norwegian development stage projects to trial earlier EOR installations in a bid to improve yields. Now seems an apt time to begin negotiations with operators, given the fact that development costs as a whole have plummeted because of the industry depression. At first glance, it would seem Norwegian firms are more likely to opt for gas injection technology to realise synergies with other upstream projects. The NPD estimates that gas injection could unlock an additional 320360 million cubic metres of oil equivalent (2-2.6 billion barrels) of reserves over its 27-field sample. But that could change should gas prices recover, driving up the costs of supplying feedstock for gas injection projects. Polymer appears more suited for realising sustained gains over a prolonged period, which might be ideal for newly launched projects. This would explain the NPD’s request for a polymer trial at Johan Sverdrup, as it would provide a sturdy testing ground to consult at other new-build projects. In any case, NPD’s willingness to push EOR – however gently or firmly – is good news for technology developers, equipment providers and chemical suppliers, who should watch development carefully. n

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InnovOil

July 2017

Safe storage on the sea floor NOV’s Subsea Storage Unit takes crude, water and chemical storage to the seafloor, enabling vital cost reductions in marginal and mature fields

S the focus on marginal and mature field development grows, a number of new production scenarios are being developed to meet the challenge. The “subsea factory” approach is by far the most popular and cost-effective in many cases, but operators are still adjusting to some of the more ambitious blueprints envisioned. Remote production facilities and subsea tie-backs are one thing, but the successful development of small pools will require bold leadership and innovation. Holding 2-3 billion barrels of oil, the majority of the world’s small pools range in size from 5-25 million barrels and lie in water depths of less than 300m. Although tantalisingly in reach, new technologies will need to be embraced if they are to be made economic. In the case of maturing assets, chemical and/or water injection facilities are often required, again raising potential development costs. Cutting the capital and operating expenditure for such equipment is crucial to keeping older fields running, and enabling new fields to be brought online. One solution already qualified for use by global oilfield technology firm NOV is the Subsea Storage Unit, or SSU. Developed by the company’s Subsea Production division, the tank enables the safe storage of crude oil, chemicals and produced water on the seafloor, and its scalable and flexible design could play a key role in development, expansion and end of field activities – potentially making small and/or maturing reservoirs profitable. NOV subsea engineer and product manager for Subsea Storage Systems Julie Lund explained to InnovOil: “The storage market of oil is dominated by rental solutions with low CAPEX investments and high OPEX. Floating oil storage units (FSUs) may encounter extreme weather conditions, risk of collisions, pollution, and require large crews and helicopter traffic. There is an industry need for a flexible, competitive and environmentally friendly storage technology, unaffected by harsh environments, winds, waves and seasonal icebergs.” Beyond the dome While other storage systems may opt for

a pressure-resistant tank, this adds to the weight and increases complexity and fabrication costs. Instead, NOV opted to use a flexible membrane protected by a dome. Oil or fluid is injected into the membrane via a hatch in the top of the dome. The membrane holds the stored medium and keeps it separate from the seawater, yet the dome itself is open to sea via free-flow openings in structure. Hydrostatic pressure acts directly on the stored fluid, ensuring that fluid pressure is greater than vapour pressure (which stays at 5 bar or less) and preventing gas separation. The membrane also negates the problem of emulsion layers and bacteria growth, again reducing the need for additional subsea treatment facilities. Multiple sizes provide flexibility according to storage volume required, based on field production data. Single SSUs hold between 5,000 and 25,000 cubic metres (cm) [62,900-157,000 barrels] of oil, at a density of 700 kg/cubic metre to 850 kg/ cubic metre. An SSU system would typically consist of one or multiple SSUs connected to a manifold, which are then controlled by an Operational Management System (OMS). The unit has negative buoyancy, achieved by filling the in-built ballast compartments with sand. Weight piles ensure its stability when deployed on the seabed, although tanks can also be fitted with skirts or suction anchors depending on soil conditions. Because it is pressure-balanced, the SSU can be deployed at any depth greater than 80m – NEWSBASE

right down to deepwater projects of 3,000m and below. Deployment itself can be conducted in a variety of ways, Lund said. “Different options have been identified and high-level evaluations have been performed – e.g. subsurface tow through a moonpool, subsurface tow with pencil buoy method or heavy lift… Due to the difference in field specific requirements and locationdependent criteria, a single recommended solution is not adequate.” According to NOV, oil would ideally be stored at export quality – suggesting that ideal developments would also contain additional subsea treatment facilities. The tanks have been designed for a typical operational life of 25 years, although storage membranes will require replacement within their 15-year expected operating life, depending on the makeup of the stored crude and the membrane material. NOV could not quote any figures for CAPEX installation without other field study information, but maintained that the benefits of reduced OPEX from crew transfer, long lifetime and the single loading system would all contribute to lower OPEX compared with FSUs or other existing solutions. The SSU will handle fluids at an inlet temperature of up to 100°C, but additional thermal management options can also be requested for storage which requires it. Lund added that the unit can be used as an integrated solution for deepwater fields,

July 2017

InnovOil

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SSU demo 2000 scale test

discharge to sea or re-injection into well with a water quality of 30 ppm or lower. NOV notes that by performing separation subsea, the pressure loss in production flowlines is kept to a minimum, enabling a lower wellhead pressure that can also lead to increased production. In a re-injection case, the produced water will also maintain pressure in the well, ensuring optimal production. In turn, this can reduce the need for topside process equipment, and help operators comply with environmental regulations on discharged water.

removing the need for an offloading booster. “It can also be designed as a mobile unit for storage of produced oil during extended well testing (EWT), which represents an economical beneficial and far more environmental friendly solution than todays ‘burn-off ’ strategy,” she noted. Leakage is mitigated via a monitoring suite in the inlet hatch. If the membrane encounters any fluid leakage, the system will detect the leak and alert the operator of the problem. The dome is then capable of containing all oil inside the SSU, preventing further leakage to sea. Any leaked fluid within the unit can then be safely extracted to a sister SSU or discharged to a shuttle tanker on the surface. The flexible membrane can then be replaced through the hatch on top of the dome. Fluid scenarios In addition to oil storage, the SSU is also designed to handle chemicals and produced

water. During development, modifications were made to produce a unit suitable for the storage of fluid with greater density than seawater, such as mono ethylene glycol (MEG), a chemical used to prevent hydrate formation and remove blockages. Typically, chemicals may need to be pumped via long umbilicals to reach the point of injection at the wellhead or pipeline. The SSU forms one vital part of the infrastructure required to site anywhere between 50cm and 25,000cm of chemicals or water on the seabed, either close to the production platform or next to the subsea wellhead. In addition to reducing the complexity and costs of umbilicals and associated equipment, storing MEG subsea also frees up space and weight on topsides and improves safety by removing the potential hazard of explosive materials. In the case of produced water, the design can be configured to separate water as a settling tank or a flotation/buffer tank for NEWSBASE

Opportunities NOV evidently sees opportunities as fields mature. Lund told InnovOil that further refinements to the system were already in the works to meet new challenges. In particular, she said: “An adaption to the Subsea Storage Unit (SSU) is proposed to be specifically optimised to smoothen out variations in liquid content, and to achieve settling of solid particles and flotation of oil droplets by gravimetric separation…to achieve required water quality of 30 ppm or lower for discharge to sea or produced water well-injection.” NOV is currently working with Chevron, Statoil and Woodside on a qualification programme for the Produced Water Treatment System, the first phase of which was completed June 2017. Phase two will begin in the autumn, and is open to additional operators and sponsors. The purchase of Kongsberg Oil & Gas Technologies’ subsea production portfolio in September 2016 also adds new possibilities to NOV’s offering, including new technologies for subsea storage, process and tie-ins, Lund said. While further analysis will be required before these refinements are complete, NOV already has robust and flexible systems to help make mature or marginal assets more attractive – it is now up to E&P firms to make bold commitments towards bringing these developments online. n Contact: Julie Lund

Tel: +45 41 91 47 06 Email: julie.lund@nov.com Web: nov.com/subsea

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InnovOil

July 2017

Michigan University algal fuel experiment. Photo by Austin Thomason, Michigan Photography

Exxon partner increases algal biofuel yield Genetic modification has produced algae which increase lipid production to 40% of its weight

HE use of algal lipids for the production of biofuel has long been touted as an alternative to conventional fossil fuels, and to cropbased biofuels, which many are concerned can lead to land-use change and pressure on food prices. Algae can also convert a much higher percentage of their mass to oil than crops, can be grown in salt water, and require only light and carbon dioxide to produce fuel. Yet the nutrient starvation process which forces oil production can stunt growth, meaning practical yields have tended to be low. That may be changing. In a recent paper published in Nature Biotechnology, oil and gas supermajor ExxonMobil and biotechnology research group Synthetic Genomics reported a breakthrough. By successfully modifying strain of oilproducing algae, the team more than doubled the algae’s oil content without significantly inhibiting its growth. Using cell engineering technologies at Synthetic Genomics, the team increased the lipid (oil) content of the Nannochloropsis gaditana strain from 20% of its mass to over 40%.

This was achieved by the team’s identification of a genetic switch in the species. Lead authors Imad Ajjawi and Eric Moellering of Synthetic Genomics note that by fine-tuning this genetic sequence, the group could alter and regulate the conversion of carbon to oil. This led to a successful proof-of-concept which allowed the algae to double its lipid fraction of cellular carbon compared with its parent, while also sustaining growth. In batch cultivation of algae, oil production is stimulated by starvation of nutrients such as nitrogen or sunlight, yet this also inhibits photosynthesis and curbs growth, leading to reduced production. The doubling of oil production in the Synthetic Genomics research is therefore a significant step forward in the technology. Although the market for algal biofuels has cooled in recent years, advances in the technology could still bring about rapid change in biofuels usage. A recent forecast by US-based Grand View Research, for example, anticipates the market growing by 8.8% per year (CAGGGR) to reach almost US$11 NEWSBASE

billion by 2025, based on its ability to supply greater yields from smaller facilities. The group has been collaborating on the task since 2009, but further research is still needed before this technology could be a commercial opportunity. ExxonMobil vice president for research and engineering Vijay Swarup noted: “Advancements as potentially important as this require significant time and effort, as is the case with any research and development project. Each phase of our algae research, or any other similar project in the area of advanced biofuels, requires testing and analysis to confirm that we’re proceeding down a path toward scale and commercial viability.” Synthetic Genomics co-founder and chairman J. Craig Venter added: “The SGI-ExxonMobil science teams have made significant advances over the last several years in efforts to optimize lipid production in algae. This important publication today is evidence of this work, and we remain convinced that synthetic biology holds crucial answers to unlocking the potential of algae as a renewable energy source.” n

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BP pushes AI Beyond Limits Supermajor’s investment arm backs artificial intelligence start-up

RTIFICIAL intelligence (AI), digitalisation and automation are all key areas of debate and innovation in the oil industry right now. That has also meant an increase in interest and capital flows outside the conventional arenas of oil and gas technology. In early June Pasadena-based Beyond Limits, an AI-focused start-up spun out of the California Institute of Technology (Caltech), announced that it had secured US$20 million in investment from BP Ventures. Leveraging technology from Caltech and the Jet Propulsion Laboratory (JPL), and from projects with NASA and the US Department of Defense, Beyond Limits is more used to finding ways of deploying its IP to interplanetary missions than managing resources on earth. However, the oil supermajor’s corporate and technology investment arm is evidently keen to see if the start-up’s expertise can aid its own push towards smarter digital operations. Reportedly, the Series B funding will accelerate delivery of industrial-grade AI software, and combine BP’s existing human knowledge with machine learning to provide “new levels of operational insight, business optimisation and process automation across all operations.” According to the two companies, the partnership could enable a step change in the way BP locates and develops reservoirs, produces and refines crude oil, and markets and supplies refined products. The software

is aimed at improving the speed and quality of decision-making and managing operational risks, as well as better harnessing and sharing some of the human expertise of BP’s team. In a statement, BP’s chief digital innovation officer Morag Watson commented: “Our strategic co-operation with Beyond Limits is a perfect fit with BP’s vision of using digital technology to help transform our organisation. We believe artificial intelligence will be one of the most critical digital technologies to drive new levels of performance across the industry.” In an interview with ZDNet, Beyond Limits CEO AJ Abdallat explained: “Whereas many popularised cognitive computing solutions in the marketplace are focused on deep machine learning applied to sensor fusion and computer vision, our cognitive computing focuses on human thinking and automates human decision processes.” This enables it to speculate, compute hypothetical scenarios and fill in data gaps using its experience – much as a human operator might do. BP Ventures – America’s managing director, Meghan Sharp, will also join the Beyond Limits board. As has been seen with other venture capital arms – last month, for example, InnovOil spoke with Statoil Technology Invest about its strategy and technology targets – BP’s investments are made with a view to enabling long-term gains for the NEWSBASE

organisation, rather than rapid technology development or financial return. BP Ventures’ portfolio is oriented towards E&P and downstream conversion process technologies, as well as a strategic focus on five key areas, including: bio and low-carbon products, carbon management, power and storage, advanced mobility and digital transformation. Highlighting the diversity of this approach, in April 2016, BP Ventures acquired a stake in RocketRoute, a flight planning business. BP’s aviation business – Air BP – had co-operated with the company previously to co-ordinate its aviation fuelling network. The company’s cloud-based services help integrate flight planning, fuel purchasing, crew briefing, flight plan filing, dispatch and flight tracking into its proprietary app. Neither is BP the first operator to embrace AI technology; GE is also putting weight behind its proprietary Predix platform, applying machine learning and AI elements to tasks such as predictive corrosion management, and has acquired a string of other AI-focused companies to help it expand its offering. With super-majors like BP and services giants such as GE pushing the technology, AI has well and truly arrived in oil and gas. Beyond Limits’ interstellar-tested technologies may be the latest to benefit from BP’s backing, but they are certainly not the last. n

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July 2017

KHI’s non-spherical idea gathers no MOSS DNV grants approval in principle to new tank design

HILE LNG tanking and shipping relies on some fairly standard designs, improvements in efficiency and carrying capacity can still have a sizable effect on bottom lines. It is therefore worth noting that early June saw maritime classification society DNV GL grant an approval in principle (AIP) to Kawasaki Heavy Industries’ (KHI) intriguing new MOSS tank design. Named after the Norwegian firm which first designed them, Moss Maritime, MOSS tanks are one of the industry’s most common designs. Typical vessels using the design may carry four or five tanks. By contrast, non-spherical tanks are used by vessel manufacturers too, but the shape is more common as part of a single continuous tank, rather than the multi-chamber design envisioned here.

KHI says that its design has the same reliability as a conventional spherical (MOSS) tank, but will hold 15% more cargo capacity. It can also be used with the company’s Panel System, a two-layered proprietary heat insulation system. The low temperature side (tank side) is comprised of phenolic resin foam (PRF) adding anti-cracking properties at low temperatures. The outer, air temperature side is made from polyurethane foam (PUF) covered with an aluminium plastic sheet. According to DNV, the new tank is an IMO Independent Type B LNG tank that has been developed for use in 180KM3 LNG carriers designed to pass through the new Panama Canal. DNV GL’s AIP involved carrying out comprehensive sloshing and buckling analyses, demonstrating that the new NEWSBASE

design provided an equivalent level of safety performance to the well-known spherical (MOSS) tank, with no filling restrictions. The approval is an independent assessment of a concept within an agreed framework, confirming that the design is feasible and no obstacles exist which would prevent its manufacture. Johan Petter Tutturen, business director for Gas Carriers at DNV GL – Maritime, said: “We worked with KHI on the delivery of the first Japanese built LNG carrier – Golar Spirit – in 1981, and that co-operation continues to this day, as she remains in DNV GL class after her successful conversion to a FSRU, a world’s first.” n Contact: Nikos Späth, DNV GL

Email: Nikos.Spaeth@dnvgl.com Web: www.dnvgl.com

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How NASA know-how is helping oil and gas

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NASA’s Dr David Urban explains to Sophie Davies how rocket engine research is benefiting oil and gas operators

HE oil and gas industry benefits both directly and indirectly from research being carried out by the International Space Station (ISS), an expert from the National Aeronautics and Space Administration (NASA) said in an interview with InnovOil. With the majority of all produced oil and gas ultimately destined for use in some kind of combustion system, although the industry benefits “indirectly,” the implications are significant, said branch chief of the Combustion Physics and Reacting Processes Branch at the NASA Glenn Research Center, Dr David Urban. “ISS combustion science research is improving the efficiency of such processes through study of fundamentals of combustion processes in ideal non-buoyant flames,” he told InnovOil. Combustion experiments at the ISS are currently focused on studying the low-temperature chemistry that controls ignition in engines, including diesel, gasoline, jet and rocket engines, Urban said. The effect is most notable in piston engines where these are designed and the fuels are selected based on control of lowtemperature ignition, according to Urban. In a gas engine this ignition causes “knock” – an undesirable phenomenon where pockets of air and fuel combust outside the intended envelope, and does not burn fuel evenly. In a diesel engine, the inverse is true – this process is used to ignite the fuel, Urban said. Varying the mixing and the fuel composition – the octane number for gas engines and the cetane number for diesel engines – control ignition. On top of that, detailed chemistry models are used by the

ISS to improve the efficiency of these engines, he said. “Our space experiments turn out to be an ideal environment to test such models,” Urban noted. Interstellar tech transfer NASA’s Glenn Research Center, located in the US state of Ohio, researches and develops new technologies for aeronautics and space flight and has produced innovative research, particularly in the areas of fluids and combustion. Its scientists and engineers were also pioneering rocket research before the US officially entered the space industry. In 2013, NASA signed a contract with Norwegian major Statoil to work together on adapting space technology to the NEWSBASE

requirements of oil and gas production. Statoil, which had begun exploring more challenging frontier environments, said at the time that it saw an opportunity to apply the kind of technology developed for harsh, remote space environments to the oil and gas field. In addition, the oil and gas industry also benefits more “directly” from the kind of research currently being carried out by the ISS, through studies of porous media and colloidal systems, Urban added. In particular, this research can have an impact on the production side of the oil and gas industry, he noted. Since the mid-1990s, the NASA Space Life and Physical Sciences programme has supported projects in gravity-dependent colloidal system physics, including through the Light Microscopy Module that has been operating on the space station since 2009. Many secondary production methods used in the oil and gas industry involve water or surfactant injection, which can produce colloidal systems, Urban said. Colloids form when particles disperse throughout another substance. Work such as this on fluid flow through porous media can also have significantly implications for oil and gas producers. While the process of knowledge-sharing and transferring technology may perhaps be slower between space agencies and oil and gas explorers than between other groups, identifying where these synergies might be is more important than ever. Oil industry innovators should ensure they look up from subsurface reservoirs every once in a while to the possibilities that may be circling a few hundred kilometres above them. n

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July 2017

North Sea workers to COMMENTARY

A new system that could see employees loaned out to rival companies could slow down the rate of job losses in the region, Sam Wright reports

ITH jobs continuing to be shed across the North Sea, the UK is looking at innovative ways to retain expertise and reduce redundancies. One interesting new approach is a loan system that is modelled on that used by professional football clubs. Last month, Royal Dutch Shell said it intended to cut 90 jobs at its base in Aberdeen. Since the collapse in oil prices, announcements such as this have become commonplace. Overall, it is estimated that 120,000 jobs have been lost across the supply chain. With a significant number of workers also approaching retirement age, fears that UK North Sea sector faces a brain drain are growing. Despite the region’s impressive resilience, which has seen many firms stay afloat by trimming costs and increasing efficiency, Deidre Michie, head of industry body Oil & Gas UK, told the organisation’s annual conference on June 6 that the overall market would remain challenging for the foreseeable future.

“In trying to come to terms with the fundamental collapse in activity and job losses we have had to move from hoping that the oil price would help us out of it to knowing that it needs to be our own actions that will play a key part in getting us through this lower for longer reality,” she said. Part of this approach has seen the establishment of Scottish government’s GBP12 million (US$15.5 million) Transition Training Fund, which so far has worked with more than 2,000 oil and gas workers facing redundancy. But the scale of the challenge has also prompted new ways of addressing the issue. One such innovation could be the footballstyle loan system currently being explored by the Energy Jobs Taskforce (EJT) and Skills Development Scotland (SDS). Setting goals Speaking to NewsBase Intelligence (NBI), SDS’ Heather Milne said that the Loan NEWSBASE

Scheme was officially launched at an event on the May 20 last year, “and continues to be promoted through the work and membership of the Energy Jobs Taskforce”. Under the plan, employers are able to nominate members of staff that are risk of redundancy, similar to how football clubs list players as being available for loan. Wages would then be paid by the hiring company, saving the employer a significant outlay in redundancy fees and associated employment charges. So far though, the project remains very much in its initial stages. However, hopes are high that it can have a significant on an industry that is undergoing rapid change. “So many jobs are being lost, and there is a lot of experience that is at risk of disappearing altogether,” Milne said. “Through the loan system, there is the option of keeping expertise in the industry and reducing redundancies.” To date, attempts at addressing this problem have struggled. Shortly after the

July 2017

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trial new loan scheme COMMENTARY

loan programme was announced, the into a valued supplier for a period of time. UK government unveiled its Oil and Gas The next is a broadening assignment, where Workforce Plan, a scheme focused on the individual would be seconded into a retraining and creating new opportunities substantive role in an external organisation in the engineering sector. But concerns over where the two organisations may or may not reduced pay and conditions has provoked have any connection with each other. fierce criticism from some quarters, in “There is also a Third Sector and charity particular the Unite union. assignment. Finally, the “The employee employee could be taken on as Similarly, schemes to encourage oil and gas workers could be taken on a consultant, with the aim of to retrain as teachers in a as a consultant, tackling a specific, short-term bid to help fill the gap in task or project.” with the aim of STEM (science, technology, In terms of administrative engineering and mathematics) tackling a specific, challenges too, the handling of subjects have also yet to have short-term task or issues such as insurance and been embraced fully. health and safety look to be project” relatively straightforward. Kicking on Heather Milne Milne continued: “The With this in mind, it is clear Skills Development premise of the scheme is that that new and innovative Scotland although the nature of the approaches are needed. “We’ve secondment will vary between, identified a number of potential areas,” in all cases ‘employment’ remains with the Milne continued. “The first is supply chain sending organisation with the secondee engagement, where an employee is seconded being bound by the codes of conduct (or NEWSBASE

similar) of both their sending and receiving organisations.” Clearly, given the enormous scale of job losses in the North Sea region, this scheme is far from being a complete solution. And to date, no loan placements have been carried out, although there has been significant interest from businesses that are eager to receive experienced workers. Yet, in a market that is cyclical as the North Sea oil and gas sector, it is clear that this approach has some potential. The scheme has received the backing of unions such as Unite, the National Union of Rail, Maritime and Transport Workers (RMT) and the Scottish Trades Union Congress, and anecdotally, it has been greeted warmly by many workers. Collaboration and the sharing of expertise was one area singled out by the Wood Review in 2014 as being key to helping maximise recovery from the UK Continental Shelf (UKCS). Anything that encourages this can only be a positive step. n

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China hypes up methane hydrates but Japan leads the way Chinese media have been talking up the potential of the country’s methane hydrates, but Japan seems set to remain ahead in terms of development of the resource, writes Graham Lees

ORGET shale gas, never mind CBM, the unconventional energy buzz in China is now focused on methane hydrates. The Chinese Ministry of Land and Resources (MLR) announced in mid-May that Chinese drillers had successfully tapped methane hydrates beneath the South China Sea in a production test. Since then, state media have been talking up the development as the country’s new energy security saviour, expected to replace declining domestic conventional oil and gas reserves. Some reports have given the impression that China is now the world leader in this new energy resource and developers will be commercialising production in the near future, but such hype is far from reality. Race to production In NewsBase Intelligence’s (NBI) view, China is nowhere near achieving commercial production of methane hydrates. Indeed, Japan is much more likely to reach commercial-level development first, and Tokyo estimates that this will happen at least six years from now – and possibly only from 2030 onwards. Nevertheless, according to the state news agency Xinhua, Chinese drillers were still producing methane hydrates in the middle of

July 2017

Flared gas from the methane hydrate deposit

this month from production tests beneath the South China Sea, though in a different area from the May test. Xinhua quoted Guangzhou Marine Geological Bureau as saying that a rig was operating 320 km southeast of Zhuhai on the Guangdong Province coast when Typhoon Merbok, with winds up to 102 km per hour, passed through the area. The rig shut down but stayed put and experienced no damage, the bureau said. The successful drilling tests carried out in early May south of Hong Kong took place in water depths of 1.266 km, the MLR said. They were carried out by Bluewhale 1, a semisubmersible rig completed in February at the state-owned CIMC Raffles Offshore yard in Yantai, northeast China. In the wake of these tests, the MLR claimed China has 80 billion tonnes of oil equivalent (586.4 billion barrels) worth of gas locked in methane hydrates. Some state media have upped this estimate to 100 billion tonnes of oil equivalent (733.0 billion barrels), but no details on the location of these resources have been provided. China energy resources specialist Chi-Jen Yang told NBI that the country appeared to have huge volumes of methane hydrates locked beneath the South China Sea, and possibly also in ice-bound mountains in NEWSBASE

the far northwest Xinjiang region, and had demonstrated a technical ability to extract samples. “However, the cost of producing natural gas from methane hydrate is still far higher by many orders of magnitude than conventional natural gas,” he said. “It is very unlikely that methane hydrate could become commercially viable anytime soon.” This is a problem the Japanese know only too well. Their first undersea drilling test off the east coast of Honshu Island, in 2013, had to be abandoned after only one week when sand leakage blocked a well. Japan claimed a world first in successfully dissolving methane hydrate from ice underneath the seabed and extracting natural gas. Now, one of the main purposes of their second production test, beginning in April and scheduled to run into this month, has been to solve the sand contamination problem, the Japanese Ministry of Economy, Trade and Industry (METI) said. The Japanese government has committed US$180 million to offshore production tests near the Daini Atsumi Knoll southwest of Tokyo. Political control US-based Chi-Jen, until recently a research scientist with the Centre on Global Change

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Minister for Land and Resources, Jiang Daming, speaking on the CIMC rig

at Duke University in North Carolina, in May published a new book, ‘Energy policy in China’, which highlights the continuing political control being exerted by Beijing, especially in energy matters. This may explain the methane hydrates hype now being spread by state media. “The political environment in China discourages open criticism against government propaganda. The situation has gotten worse after the [President] Xi Jinping administration tightened its control on Chinese media,” ChiJen said. “Certainly some factions in the Chinese establishment want to get more [research and development] funding for methane hydrates and they have managed to secure the support from top Communist leaders. The most impressive news about the recent methane hydrate development is that the Communist Party Central Committee and the State Council jointly sent their congratulations,” he added. “Those who know better dare not contradict government propaganda. The authoritarianism and lack of free press leads to misinformed policy priorities.” Examples of this include state media once lauding Chinese NOCs’ investments in oilfields in Angola and Venezuela – investments that now look like expensive mistakes.

What next? In the meantime, CIMC Raffles is nearing completion of a second deepwater semisubmersible rig, Bluewhale 2, which partner Frigstad Group has said will be ready for launching by the third quarter of the year. The China Geological Survey, part of the MLR, was quoted by China Daily in May as saying three more separate drilling tests would be conducted in the same region of the South China Sea to accumulate more experience and data, but provided no timetable. Xinhua on June 11 quoted the Guangzhou Marine Geological Bureau as saying that ongoing production of methane hydrates amounted to 6,800 cubic metres per day, and that strict measures were in place to protect the environment. “We are monitoring the air, sea water, seabed and the exploration equipment. We also closely following the amount of methane and carbon dioxide [emitted],” the Guangzhou Marine Geological Bureau’s director, Ye Jianliang, said. The Chinese media’s excitement about methane hydrates bears similarities to its reaction when Beijing decided that shale gas would be the new energy saviour and announced unrealistic production targets. These have since been scaled back as producers have found that although China has large NEWSBASE

reserves of gas locked in shale formations, much of it is difficult to access owing to challenging geology and terrain. NBI expects that Japan will be much more focused on overcoming the challenges related to methane hydrate production, making it likely to achieve some level of commercialisation before China. Supporting this view is the fact that until the emergence of methane hydrates in its territorial waters Japan was lacking any substantial domestic energy resources. Reports have estimated that Japan has spent US$30 billion on coal, oil and gas imports since the shutdown of the country’s nuclear power plants (NPPs) following the Fukushima accident in 2011. In addition, the Japanese government works closely with the country’s large state and private industrial companies. As well as committing US$180 million to methane hydrate development, Tokyo has also brought together numerous businesses to promote new technology to help commercialise the resource as quickly as possible, Japan’s Nikkei news agency reported. The heavy hand of China’s state bureaucracy and the continuing dominance of the NOCs, despite Beijing’s promise to open the upstream sector more to outsiders, will likely ensure that Japan leads the way on methane hydrates. n

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July 2017

NEWS IN BRIEF

OGTC looks for asset integrity and small pools inspiration THE Oil & Gas Technology Centre (OGTC) has launched two new ‘Calls for Ideas’ to identify, support and fund solutions which use robotics to reduce inspection costs, and to unlock the 225 marginal discoveries in small pools across the UK Continental Shelf (UKCS). Each call has a fund of c.GBP1 million to invest and organisations can grab a slice if they demonstrate their technology concept or idea can deliver a transformation against a specific theme. Asset Integrity: Using robotics for nonintrusive inspection of pressure vessels and tanks; Using robotics for confined space entry to pressure vessels and tanks. Small Pools - standardising the subsea development life-cycle approach to support: rapid engineering and delivery of a project; full interconnectivity between modular subsea components; the re-use of subsea equipment from one field to another; interoperability with present and future

systems; and the use of a range of key supplier specific subsea components. The Centre welcome submissions from June 5 to July 30 where full technical details and an of overview of the process will be available on our website. Rebecca Allison, Asset Integrity Solution Centre Manager, said: “Our goal is to eliminate the impact of asset integrity on operational uptime by 2026. We’re looking for deployable robotic technologies for pressure vessel and tank inspections that reduce cost, improve quality, increase efficiency and enhance safety. Chris Pearson, Small Pools Solution Centre Manager, added: “Designing plug and play subsea equipment for developing marginal oil and gas fields is an opportunity recognised by all exploration and production companies. Industries such as nuclear and automotive have proven that plug and play technology can significantly reduce life-cycle costs and help create new business models. Submissions will be evaluated against a range of criteria including value creation, sound scientific principles, time, cost and risk reduction. Successful organisations will receive professional guidance, funding, and support to develop their ideas towards the next stage of development. OGTC

Colette Cohen, OGTC chief executive NEWSBASE

Sapura wins US$200m worth of EPCI work SAPURA Energy’s offshore division has secured US$205.96 million worth of engineering, procurement, construction and installation (EPCI) contracts, the Malaysian firm said last week. It was awarded a subcontract for works on PTT’s Zawtika field development in the Gulf of Moattama offshore Myanmar. Zawtika lies in 120-160 metres of water. Works will include installing new pipelines and offshore wellhead platforms, as well as upgrading existing ones, before March 2018. Sapura Offshore also secured an EPCI contract for upgrades at Royal Dutch Shell’s Seria Crude Oil Terminal (SCOT) export system in Brunei. Sapura will take charge of EPCI for the SCOT’s new mooring and manifold systems, while also dismantling elements of SCOT’s obsolete installations. It expects to fulfil the contract by April 2018. Sapura Energy was previously known as SapuraKencana before being rebranded in February. The Kuala Lumpur-based firm was hit heavily by low oil prices, which undermined offshore services demand especially because of the higher cost of such developments. Tentative signs of recovery have since emerged for the Malaysian services sector. On May 11, Sapura Energy said operators were starting to consider restarting developments which were paused amid the industry crash. Sapura Energy’s financials are also improving after a concerted cost-cutting drive during 2015 and 2016. The firm swung into a 208.3 million ringgit (US$48.8 million) net profit for the fiscal year ending January 2017, in a result which surpassed analyst expectations. It reported a debtto-equity ratio of 1.16 times, compared with 1.34 times one year earlier, while impairments eased to 668 million ringgit (US$156.6 million) from 2 billion ringgit (US$469 million) in 2016. As a result, Maybank Investment Bank Research (Maybank IB) lifted its 2018 earnings projection for Sapura Energy by 110% to reflect lower drilling costs and better profits from associates, according to Malaysian daily The Star. On June 8, Maybank IB pointed to stateowned Petronas’ 60 billion ringgit (US$14 billion) capital expenditure budget for 2017

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NEWS IN BRIEF

as further evidence of the tide seemingly turning for local services firms. “We are slowly seeing a revival in upstream activities. Tenders in the pipeline are also on the rise, of which most are backloaded in the second half of 2017,” it said. Edited by Andrew Kemp Andrew.kemp@newsbase.com

ABS issues AIP for Chiyoda’s floating LNG power plant concept ABS has granted Approval in Principle (AIP) for a floating LNG power plant and Floating Storage and Regasification Unit (FSRU) design concept developed by Japan’s Chiyoda Corporation. “As the energy mix shifts and global demand for gas increases, concepts like this will reshape how energy is supplied,” says

ABS Vice President for Global Gas Solutions Patrick Janssens. “By working closely with Chiyoda, we were able to help them prove the feasibility of this novel and innovative concept.” This concept offers a new approach to delivering new sources of power to remote areas of the world. The conceptual design is based on existing LNG carriers which are converted into floating power plants with small (~72 MW) to medium (~400 MW) scale power generation capabilities. In reviewing Chiyoda’s floating LNG power plant concept, ABS applied its relevant Rules and Guides to confirm that the conceptual design meets the intent of applicable class requirements. “By applying ABS’ robust guidance, we were able to develop a concept that meets operational demands and advances safety,” says Chiyoda Corporation Project Manager Toyomitsu Kanai. “By basing this concept on existing LNG carriers, we are able to reduce constructions costs and shorten delivery times. We look forward to developing this concept further and expanding the LNG value chain to new markets.” ABS

NEWSBASE

NPD seeks joint development plan for Krafla and North of Alvheim STATOIL and Aker BP have been told to draw up distinct proposals for the joint development of their respective KraflaAskja and North of Alvheim clusters in the Norwegian North Sea. The pair are said to be in conflict over a common blueprint, and Statoil is unlikely to accept surrendering operatorship over acreage where it controls the bulk of resources. Statoil’s Krafla-Askja holds an estimated hydrocarbon resource of around 260 million boe, compared with the estimated 172 million boe held in the North of Alvheim prospect. Oslo reportedly decided to concentrate minds by demanding both firms provide an assessment of the resource and value potential of their proposed joint development plans.

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NEWS IN BRIEF

production increased, driven by improved efficiency.

ficant scope for further efficiency improvements, an Edited by Ryan Stevenson a day could be generated from underperforming ryans@newsbase.com .

UK oil and gas production efficiency rises to 73%

continuing downward trend in the number of se in well losses in 2016 could be a forewarning en recent low levels of investment. Export losses on-year with terminal outages showing significant This highlights a continued requirement for action.

es have improved in 2016 highlighting the significant made by industry through initiatives such as the askforce’s (PETF) compression sub-group. There cklog of economically viable activities that could CS.

PRODUCTION efficiency (PE) on the UK Continental Shelf (UKCS) has risen for a fourth consecutive year to 73%, according

OGA

UKCS production efficiency & production

Figure 1 : UKCS production efficiency and production 2000

Total UKCS Production

100%

Maximum Potential

90%

Production Efficiency

80%

1500

70% 60%

1000

50% 40% 30%

500

20% 10%

2008 2009

2010

2011 2012 2013

2014

2015 2016

*In 2015 methodology was updated in line with new SPE draft guidelines.

Figure 2 : UKCS production losses 2011–2016 Market Losses Plant Losses 73% Production Efficiency Export Losses Well Losses

450 400

Continued improvement, up 2% on 2015

350 300 250 200 150

+270 Million Barrels

100

Additional production from efficiency improvements since 2012 efficiency low point (60%)

50 0

2011

2012

2013

2014

2015

2016

£2.8 Billion

Potential “prize” if underperforming hubs hit 80% target in 2016, an additional 220,000 boe day (Oil @£50/bbl and Gas @ 40p/therm)

+3% Water Injection Efficiency Increasing production by > 1mmboe

NEWSBASE

Production efficiency

Production / Production potential (mmboe)

summary

to a new publication released by the Oil and Gas Authority (OGA), representing an additional production of 12 million barrels of oil equivalent (boe) compared to 2015. The report, UKCS Production Efficiency in 2016, compares actual production in 2016 to the theoretical maximum economic potential of the fields and associated infrastructure, compared to previous years. Data were collected as part of the OGA’s 2016 UKCS Stewardship Survey, which allowed for a more in-depth analysis in key areas, for example in looking at the major causes of lost production. PE is an important indicator for the industry and the OGA as a core element of production optimisation and asset stewardship performance. PE is also a key focus area for the Maximising Economic Recovery (MER) UK Asset Stewardship Task Force. In its Activity Plan 2017 and 2018, the OGA identified PE as a Key Performance Indicator (KPI) for industry, with a target of 80% PE for the UKCS by the end of 2018. Recent years have seen the UKCS reverse the declining trend in both PE and overall production. From 2012 to 2016, losses have fallen by 157 million boe while production has risen by 34 million boe.

Losses (mmboe)

Statoil and Aker BP are understood to have claimed they will need until December to finalise these concepts, while Oslo has stressed both firms must sign informationsharing contracts to further collaboration. It seems to be a rare instance of the Norwegian Petroleum Directorate (NPD) enforcing guidelines that obligate operators to harmonise development plans across several deposits to optimise resource recovery. This has become increasingly important as the focus on the Norwegian Continental Shelf (NCS) moves towards marginal fields and frontier basins. Maximising efficiency at neighbouring deposits also moved up the agenda with the collapse of oil prices in 2014. That year, the NPD asked Statoil to consider areawide solutions for Johan Castberg in the Barents Sea, a frontier region where existing infrastructure is sparse and development costs can be prohibitive. Krafla-Askja and North of Alvheim hold almost 400 million boe of reserves across several deposits. Aker BP already owns a 25% stake in the Krafla-Askja cluster, and so stands to consolidate its investments if Oslo enforces a unitisation agreement. Aker BP added 83 million boe of reserves UKCS Production Efficiency 5 from exploration probes in both North of Alvheim and Krafla-Askja last year. The fields are 2. situated in waters ranging in depth UKCS production efficiency from 100 to 200 metres, and are perhaps best suited to a2.1single fixed platform alongside UKCS overview cy unmanned installations at satellite deposits. UKCS PE increased for the fourth consecutive year, reaching 73%. This is an improvement of 2% on 2015 which represents an additional It is understood that one option would be production of 12 million barrels of oil equivalent due to efficiency. for Aker BP’s Frigg Gamma Delta discovery PE in the UKCS fell from over 76% in 2008 to a low of 60% in 2012. Recent years have seen a reversal in the declining trend in both PE to host theandcentral platform, anchoring the overall production. development between North of 2012 Alvheim’s Production losses have been falling since and are continuing to fall, even as total production in the UKCS rises. From 2012 to 2016 other deposits, Froy. losses haveLangfjellet fallen by 157 millionand boe whilst production has risen by 34 million boe. Krafla-Askja five deposits ncy (PE) has risen for acomprises fourth consecutive Total losses in 2016 were 210 million boe. ched 73%, drivingfurther increased production discovered to the south in PL035 Plant losses continue to be the largest loss category in 2016 dom Continental Shelf (UKCS). representing 60% of total losses (Figure 2).West and and PL272, including the Askja The maximum potential of the UKCS fell slightly boe in 2016,was mainly due to East deposits, where 19-44 million ncy contributed an additional million barrels of and continued decline a significant field12 coming off production plateau in well potential in some ageing fields. Despite the fall in potential, uncovered in 2014. 016, which is more than the UKCS’s 7th ranked

Pioneering ‘fingerprint’ test will build confidence in geological storage of CO2 A TEST developed by Scottish scientists to check for leaks from carbon capture and storage (CCS) sites, where man-made carbon dioxide (CO2) emissions are stored deep underground, has been used for the first time in Canada. Researchers from Scottish Carbon Capture & Storage (SCCS) have developed a way to measure tiny traces of inactive natural gases, known as noble gases, found in CO2. These noble gases vary depending on whether the CO2 is from just below ground or deep below, enabling scientists to fingerprint a sample and pinpoint its source. The technique, developed by scientists at the University of Edinburgh, has been conclusively used to investigate an alleged leak from CO2 injected underground at a farm in Saskatchewan, Canada. The test showed that high levels of CO2 recorded on the farm arose from nearby wetlands and were not leaking from a CCS site at the nearby Weyburn Oil Field. While studies have shown that small amounts of CO2 seepage carry no significant threat to human health, the new test will allow scientists and storage site developers to reassure residents that CO2 storage sites are secure. The technique will be useful in countries, such as Canada and the USA, where onshore CO2 storage is already underway. In the UK, which has ample offshore CO2 storage, scientists are researching how this test can be combined with other offshore monitoring methods. Dr Stuart Gilfillan of the University of Edinburgh’s School of GeoSciences, who led the study, said: “Carbon capture and storage is an essential means to curb emissions of greenhouse gases, which is needed to limit global warming to 2°C, as internationally agreed recently in Paris. Securely storing captured CO2 is critical to its success and our method of identifying any leaks should give assurance to local communities. Our work provides a simple way to easily and unambiguously spot leaks from future

July 2017

InnovOil

page 37

NEWS IN BRIEF

Over the last three years, Timan-Pechora has invested 5 billion rubles (US$88.4 million) in the development of the Inta fields. Progress was halted in 2016 as the company faced financial problems, although work was resumed earlier this year. “The conclusion of the co-operation agreement between the Government of the Republic of Komi and the company is the first step towards the integration and consolidation of administrative, resource and investment potentials and intentions with a view to effective and mutually beneficial cooperation,” Timan-Pechora general director Bogdan Fedorishin said in a statement. Komi’s regional government has welcomed the Inta fields’ development as well as the construction of a gas-processing plant, which is set to diversify the city’s economy away from its dominant industry, coal. Timan-Pechora’s remaining upstream assets are all located in the Komi region, comprising 12 licence areas. Edited by Joe Murphy josephm@newsbase.com

Stuart Gilfillan and Jerry Sherk undertake more sampling at one of the Canadian test sites storage sites, using the fingerprint of noble gases that the CO2 picks up during storage.” The study has been published in the International Journal of Greenhouse Gas Control and was funded by the Natural Environment Research Council and SCCS. SCCS

Komi explorer to build new gas complex REGIONAL Russian firm Timan-Pechora Gas has agreed a two-year plan with local authorities in Russia’s northern republic of Komi to start commercial gas production and construct a gas-processing complex near the town of Inta. The company announced on June 2 that the agreement had been signed by Komi’s governor,

Sergey Gaplikov, and the general director of Timan-Pechora, Bogdan Fedorishin, at last week’s St Petersburg International Economic Forum(SPIEF). Timan-Pechora has subsoil rights to 5,000 square km of acreage in the Inta area, comprising two known gas fields: Intinskoye and Kozhimskoye. Combined, they hold 24 bcm of natural gas in ABC1+C2 reserves. Seven exploration wells have been sunk since the fields were discovered in 1977. Timan-Pechora plans to complete the final exploration stage by the end of the year, after which the company will publish new reserve estimations. Commercial gas production is expected to begin by 2020 and the company will build a gas-processing facility nearby, output from which will be sent to market via the Bovanenko-Ukhta pipeline. The agreement signed last week is part of Timan-Pechora’s development programme at its Inta blocks up to 2022. NEWSBASE

Aquaterra Energy wins multi-million pound North Sea abandonment contract AQUATERRA Energy has won a major contract to supply subsea high pressure riser (HPR) equipment and services for a subsea abandonment project in the central North Sea. The multi-million pound deal will see Aquaterra facilitate the abandonment of ten

George Morrison, MD of Aquaterra Energy

page 38

InnovOil

July 2017

NEWS IN BRIEF

subsea wells via deployment of a subsea HPR system from a jack-up rig. The scope of work could be extended to include two further subsea wells bringing the total number of abandonments to 12. Riser analysis was completed in-house by Aquaterra and validated by Bureau Veritas. It has confirmed a 50-year return storm operating envelope after HPR and rig optimisations were implemented. This has simplified the project operationally and reduced costs to the operator overall. Aquaterra’s Initiation Engineering or ‘Well Start’ specialism has been implemented on the project to deliver a one-stop shop for extensive expertise to optimise well activity by taking responsibility for the entire first phase of the well. This approach minimises third party interfaces across a client’s project and addresses supply and equipment requirements, before the introduction of a blowout preventer. It can also mitigate risk and cut down on costly logistics, capex/opex, the number of crew involved and therefore, helicopter and accommodation needs. AQUATERRA

Japan aims to create LNG bunkering hub JAPAN is stepping up efforts to make the Port of Yokohama an international LNG bunkering hub, as the number of LNGfuelled ships is expected to rise owing to tougher environmental regulations. In the latest step in such efforts, Yokohama-Kawasaki International Port Corp. (YKIP),which operates the ports of

Yokohama and Kawasaki, has joined two London-based international organisations promoting the use of LNG as fuel for ships. The two international organisations are the Society for Gas as a Marine Fuel (SGMF) and SEA-LNG. SGMF has more than 110 members, including shipping firms, LNG suppliers and port authorities, while SEA-LNG has about 20 organisations, including shipping firms and LNG suppliers, as its members. The other SGMF member Japanese firms include Mitsui OSK Lines (MOL) and Kawasaki Heavy Industries, while the other SEA-LNG member Japanese firms include Nippon Yusen Kabushiki Kaisha (NYK Line), Mitsubishi and Marubeni. YKIP said in a statement: “We will now build an international network through the two organisations and push ahead with efforts to establish an LNG bunkering hub at the Port of Yokohama.” YKIP was established in January 2016 by the municipal governments of Yokohama and Kawasaki as a joint venture company to operate the ports of Yokohama and Kawasaki on Tokyo Bay in an integrated manner. The Japanese government later became YKIP’s biggest shareholder with a 50% stake. In June 2015, the Japanese Ministry of Economy, Trade and Industry (METI) compiled a report on the nation’s future resource and fuel policy which calls for, among other things, the use of LNG to be promoted in the transport sector. The report notes that Japan currently relies on oil products for more than 95% of fuels used in the transport sector. The document stresses the need to diversify fuels used in the transport sector, especially by trucks and ships. The Sakigake tugboat, Japan’s first LNG-

NEWSBASE

fuelled vessel and owned by NYK Line, has also been engaged in work, mainly at the ports of Yokohama and Kawasaki, since August 2015 to verify the effectiveness of LNG as a marine fuel. According to NYK Line, Japan’s biggest shipping firm followed by MOL, using LNG will lower emissions of CO2 by about 30%, NOX by about 80% and SOX by 100%, compared to heavy oil. Edited by Richard Lockhart richardl@newsbase.com

Schlumberger Introduces cased hole formation evaluation and reservoir monitoring in a single tool SCHLUMBERGER introduced the Pulsar multifunction spectroscopy service at the SPWLA 58th Annual Symposium. The new service provides the industry’s first complete cased hole formation evaluation and reservoir saturation monitoring with openhole logging quality. This next generation in pulsed neutron logging features multiple detectors and a high-output pulsed neutron generator to significantly improve acquisition accuracy and increase both logging speed and measurement precision. The Pulsar service measurements are complemented by powerful algorithms delivering robust

July 2017

InnovOil

page 39

NEWS IN BRIEF

Silica’s Sparta plant

answers that compensate for variations in the borehole fluids and completions to make reservoir monitoring in complex conditions a reality. The Pulsar service simultaneously obtains self-compensated traditional cased hole measurements, an expanded suite of elements including total organic carbon (TOC) and the new fast neutron cross section (FNXS) measurement. Directly sensitive to the volume of gas in the formation, the FNXS measurement differentiates and quantifies gas-filled porosity from liquid-filled and tight zones without requiring any openhole data input. The service has been run to successfully guide completions designs in more than 60 wells in all the major shale plays in North America. Worldwide, nearly 500 wells

have been logged by the Pulsar service for reservoir monitoring and bypassed pay identification. SCHLUMBERGER

US Silica to build new Permian frack sand plant US Silica Holdings is ready to start construction of a new US$225 million frack sand mine and plant in West Texas to cater to rising demand for proppant in the Permian Basin. The facility will have a production capacity of around 4 million tpy, and is part of the company’s wider plan

to add around8-10 million tonnes of new brownfield and greenfield capacity to meet surging frack sand demand. Construction on the project will begin immediately and initial output is anticipated in the fourth quarter of this year, Frederick, Maryland-headquartered US Silica announced on June 12. The project, which is set to be funded using cash on hand and cash flow from operations, will be supported by long-term supply contracts with oilfield services firms, which include cash pre-payments, US Silica said. It added that the 3,200-acre (13 square km) site had over 30 years of reserves of fine grade 40/70 and 100 mesh sand with “excellent” physical properties. “We believe we’ve selected one of the most advantaged sites in West Texas with good availability of water, easy access to Interstate 20 and a location that is equidistant to the hearts of both the Delaware and Midland Basins,” said US Silica’s president and CEO, Bryan Shinn. “[Our] customers told us clearly that they want more local sand supply in the Permian to support future well completions. Their willingness to negotiate long-term supply agreements for this new capacity and to potentially commit their own capital to the project demonstrate the confidence they have in US Silica and the tightness of the frack sand market now and in the future.” Shinn added that the company expected to enter into similar agreements for other capacity expansion projects currently under way. Demand for frack sand in North America is rising as shale drillers return to work after the downturn and as more proppant is used during fracking. Edited by Anna Kachkova annak@newsbase.com

Yokohama, Japan

NEWSBASE

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InnovOil

What next …?

To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections To make an enquiry or request more information on NOV’s subsea storage unit (SSU), contact subsea engineer and product manager Julie Lund on +45 41 91 47 06 or email julie.lund@nov.com For more information about the LumaSense Pulsar 4, or any of the company’s other temperature monitoring equipment , contact LumaSense Technologies on +49 69 973 730, or email info@lumasenseinc.com Open Water Power’s aluminium battery design could radically alter the performance and capabilities of UUVs. To make an enquiry, you can contact the company via info@OpenWaterPower.com or visit www.openwaterpower.com Nel Hydrogen claims to supply the most robust and reliable electrolysers in the world. If they could aid your manufacturing, downstream or gas supply business, contact Bjorn Simonsen on bjorn.simonsen@nelhydrogen.com or visit http://nelhydrogen.com/ If the Chalmers University team’s investigation into yttrium-platinum nano-alloys could be of benefit to your hydrogen business, get in touch with Björn Wickman via +46 31 772 51 79, or email bjorn.wickman@ chalmers.se CSIRO’s vanadium alloy membrane could provide new opportunities for hydrogen storage and transport. To learn more, contact Dr Michael Dolan on +61 733 274 126 or email michael.dolan@csiro.au Laser-induced graphene (LIG) has shown remarkable abilities in removing bacteria. You can contact the Tour Group at Rice University via tour@rice.edu or at www.jmtour.com/ To learn more about KHI’s non-spherical MOSS tank, and DNV’s approval in principle of the design, contact Nikos Späth, DNV GL via Nikos.Spaeth@dnvgl.com

NEWSBASE

July 2017

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track & trace Supply chainOilfield Services from Swire

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production

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the latest innovations

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

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