InnovOil Issue 56 September 2017 by NewsBase Ltd.

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Bringing you the latest innovations in exploration, production and refining Issue 56

CAPTURING AT TROLL

Statoil to evaluate CCS project at the Troll field Page 8

EYES ON EUROPE

A look at topics and technology from SPE Offshore Europe 2017 Page 13-25

SVERDRUP TAKES SHAPE

Installations continue at Norway’s flagship development Page 28

September 2017

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Inside Contacts: Media Director Ryan Stevenson ryans@newsbase.com Media Sales Charles Villiers charlesv@newsbase.com Kevin John kevinj@newsbase.com

Methane detection

Venturer FPSO in Australia 7 Inpex’s Ichthys project falls into place

Norway’s North Sea CCS

Statoil to evaluate carbon capture

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On the radar

Outside the world of oil and gas

OFFSHORE EUROPE 2017 13

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

Decommissioning

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Thoughts on innovation and collaboration

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Underwater laser cutting from UCS

Keeping decom costs below US$50 bn

Cover image: Statoil’s Troll C platform Photo by Øyvind Hagen

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ction ations in exploration, produ Bringing you the latest innov

Ball Aerospace’s LIDAR-based system

Editor Andrew Dykes andrewd@newsbase.com

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A note from the Editor

Christophe de Margerie

Johan Sverdrup

Maiden voyage through the Northern Sea

and refining September 2017

Issue 56

CAPTURING AT TROLLluate

Progress in the Norwegian North Sea

Statoil to eva CCS project at the Troll field

WiSub 32

Page 8

A new subsea docking system

Remote witnessing

News in brief

DNV drives subsea surveillance PE EYES ON EURO Offshore Europe 2017 and technology from SPE A look at topics Page 13-25

TAKES SHAPE p development SVERDRUP continue at Norway’s flagshi

Contacts 40

Installations Page 28

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A note from the Editor A COUPLE of years can roll around pretty fast. As we prepared this month for one of the biggest events in the European oil industry calendar, September’s SPE Offshore Europe 2017, it seemed prudent to reflect on the changes of the past two years. In 2015, keynote chairman Michael Engell-Jensen discussed how innovation could improve safety and costs in an industry feeling the severe bite of low oil prices. Priorities may have changed since then – efficiency and cost reduction have to some extent overtaken other concerns – but other forecasts for technical innovation have been heeded. Ahead of the 2015 conference, technical chairman Charles Woodburn told InnovOil of the importance of “cost-effective, life-of-field subsea well intervention. There is currently a large gap in the market for this technology.” It is therefore promising that we cover an example of just such a technology in this month’s issue. In another sign of shifting priorities, the conference’s deepwater zone has now given way to the decommissioning zone, a reflection of a sector now facing up to the realities of dismantling and removing assets, rather than prolonging them indefinitely. In this month’s issue, we speak with several members of the “Decom North Sea: Global Late Life and Decommissioning Practitioners” panel to get their insight into how technology can deliver necessary cost reductions.

Given the changed backdrop of the past two years, this year’s delegates will assemble under the fitting banner of ‘Embracing New Realities: Reinventing our Industry.” In her welcoming letter to the 2017 conference, this year’s conference chair, Schlumberger Drilling Group president Catherine MacGregor, notes: “Learning the lessons from the most severe downturn in the industry for the past 30 years, there is no doubt that the industry has to reinvent itself… The current situation is an opportunity for the industry to rethink beyond just cost efficiency and embrace new technologies, new types of collaborations and business models, as well as different ways of working that lead to new, sustainable outcomes.” We look forward to meeting the InnovOil readers and technology developers at the forefront of this reinvention in Aberdeen this month. Despite our focus on Europe, we also pay attention to a number of technical innovations from across the globe. In the US, for example, new advances in LiDAR have allowed Ball Aerospace & Technology to map methane emissions on the ground from a fixed-wing aircraft – faster and at a lower cost than the helicopter or ground surveys used today. Meanwhile, in Australia, Inpex’s Venturer FPSO has set sail for its mission in the Browse Basin. All this and much more is inside. We are pleased to present the September issue of InnovOil.

Andrew Dykes Editor

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InnovOil

September 2017

Turning up the DIAL on methane detection Cheaper, faster methane detection using Ball Aerospace’s LIDAR-based Methane Monitor system

ITH legislation around emissions reduction becoming tighter around the world (the US perhaps being the exception), companies are under more pressure to monitor accurately and control emitted gases and potential leaks. Until recently, that process has been inaccurate and labour intensive, often involving survey work undertaken by human teams equipped with infrared cameras – sometimes by low, slow helicopter missions for remote assets such as pipelines. These teams are deployed several times a year, and at considerable expense given the poor quality of the results. In January, InnovOil covered Quanta3 and its efforts to test static, sensor-based methane monitoring equipment at Statoil unconventional wells in Texas. However, an altogether new approach has been proposed by Steve Karcher, Phil Lyman and Jarett Bartholomew of Ball Aerospace & Technology. The team’s solution, Methane Monitor, enables operators to identify methane emissions on the ground from a fixed-wing aircraft. The sensors used are mounted on a single-engine, fixed-wing aircraft – offering lower costs than sensors mounted on helicopters – and can image the full plume of methane gas, allowing real-time detection and quantifying of fugitive emissions. LIDAR While many methods use the aforementioned sensor approach, this system is based on LIDAR (Light Detection and Ranging) – or more specifically differential absorption LIDAR, also known as DIAL. As explained by the engineers in their write-up “Embedded DIAL System for Measuring Fugitive Natural Gas Emissions”, this system uses two laser wavelengths: one which is resonates with the molecule of interest, and one which does not. As the on-resonance wavelength is more strongly absorbed by the molecule, the difference between the two

Actual methane plumes discovered by Methane Monitor. Above is real-time data and below is postprocessed data, both overlaid on Google Maps. The straight green lines are overlays of buried oil and gas infrastructure. The legend ranges from 0 ppm-m (blue) to 1,000 ppm-m (red) CH4 above background. For reference, the current background level of methane globally is approximately 1.9 ppm

signals directly correlates with the amount of the chosen molecule in the laser’s path. A wavelength of around 1,645.55 nm is used as the on-resonance signal for methane, and is beamed every few nanoseconds, interspersed with a signal which passes straight through the molecule. Taking NEWSBASE

anywhere between 1,000 and 10,000 measurements per second, depending on the survey, the DIAL system calculates the difference between the signals to indicate gas concentration. This is collated in an application based on National Instruments’ LabVIEW platform. These readings are combined with recordings of altitude and geo-location, enabling operators to overlay the plume tracking onto images taken during flight, and/ or visualisations such as Google Maps. Doing so also allows users to identify a complete image of the plume from an asset or facility, rather than more widespread or environmental emissions from agriculture, for example. In the paper, Ball authors note: “We have detected methane flow rates as low as 50 standard cubic feet per hour (SCFH). We can configure Methane Monitor’s sensing swath width up to 200 metres wide. The system has a spatial resolution and geo-location accuracy of better than 2 metres each.” In practice, it means that a small aircraft can collect data over hundreds of miles, all while flying at altitudes of around 1,500 feet, and speeds of 100mph. Pipeline surveys in particular can therefore be done cheaper, faster and more accurately. Award winning Recognising the potential of the system, the innovation recently won the Engineering Impact Award for Energy at National Instruments’ NIWeek 2017. Ball now intends to incorporate a newer digitiser in its latest generation of Methane Monitor, raising altitude to around 3,000 feet (900 metres) and extending the surveyed area by five times, with a doubling of spatial resolution. “The next-generation instrument can make cost-effective [surveying] of highly branched, low pressure gas distribution assets possible. It can also facilitate leak [surveys] of oil and gas gathering lines, which are broadly distributed across oil and gas formations,” the team noted. n

September 2017

Ichthys Venturer reaches Australia

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Venturer now moored in the field

The latest piece of Inpex’s Ichthys project falls into place with the arrival of the Venturer FPSO

HE final component of Australia’s mammoth, US$34 billion Ichthys LNG project arrived in Australian waters this month, marking another step in the road towards the country’s incoming LNG boom. The Ichthys Venturer floating production, storage and offloading (FPSO) facility left DSME’s yard in South Korea almost a month ago, taking 26 days to reach the country’s territorial waters. At the time of writing the vessel was travelling off the coast of Western Australia to its permanent mooring position in the Browse Basin, about 220 km offshore. Once the Venturer is moored in position at the Ichthys Field, in water depths of up around 250m, it will commence hook-up and commissioning. “The safe completion of the 5600 kilometre, 26 day tow of the Ichthys Venturer from South Korea to Australian waters is another significant stride forward for the Ichthys LNG Project,” said the project’s managing director Louis Bon in mid-August. “The Ichthys Venturer is one of the largest and most advanced offshore facilities of its kind in the world, and can accommodate up to 200 people.” With service required for a 40-year project life in a cyclonic environment, Bon added that the Venturer was “setting new

benchmarks for durability.” The 336m long FPSO can hold up to 1.12 million barrels of condensate, and will process, stabilise and store hydrocarbons delivered from the central processing facility (CPF) Ichthys Explorer, periodically offloading it to tankers for export to market. The CPF is the world’s largest semisubmersible platform, built by Samsung Heavy Industries in South Korea, and arrived at its mooring site in the Browse Basin at the end of May. The Ichthys Field is being developed as part of a joint venture between Japanese operator Inpex and partners Total, CPC from Taiwan and the Australian subsidiaries of Tokyo Gas, Osaka Gas, Kansai Electric Power, JERA and Toho Gas. At its peak it is scheduled to produce 8.9 million tonnes of LNG and 1.6 million tonnes of LPG per year, as well as just over 100,000 barrels of condensate per day. The company announced in January that installation of subsea infrastructure and equipment had been completed successfully, involving a subsea network comprised of a 110-metre high riser support structure, five manifolds, 139 km of flowlines, 49 km of umbilicals and flying leads, 2,640 tonnes of production and MEG spools, five subsea distribution units and a subsea distribution hub. NEWSBASE

The network also links to the 890-km export pipeline which will carry gas and condensate to onshore facilities near Darwin. The arrival of the Venturer is an important milestone for the consortium, especially given the ballooning costs and overruns seen during development of the gigantic project. Since it was approved in 2012, costs have risen by around 10%, and first LNG production is now expected in March 2018 – around a year later than originally envisioned. It has also added tension to the race between Inpex’s Ichthys and Royal Dutch Shell’s Prelude megaprojects. The latter, a US$12.6 billion, 488m long floating LNG production and processing facility, is one of the largest vessels ever built. Prelude arrived at its destination in the Browse just weeks before the Venturer, in late July. It is expected to start-up in 2018 too, and although Shell has been hesitant to provide a more specific timeline, current estimations suggest it maybe sometime between April and September next year. Both are certainly engineering accomplishments, but extra prestige may be taken from the consortium which achieves first gas. With all the facilities in the water, the race is now on. n

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InnovOil

Norway announces further commitment to North Sea CCS Statoil will evaluate a carbon capture and storage programme near the Troll field, reports Sam Wright

ORWAYâ&#x20AC;&#x2122;S carbon capture and storage (CCS) state enterprise Gassnova SF has assigned Statoil to evaluate a large potential CCS programme on the Norwegian Continental Shelf near the Troll oilfield. The project could have high commercial potential, if the technical issues can be overcome. Statoilâ&#x20AC;&#x2122;s proposed CCS system will capture and store carbon dioxide from three onshore plants, shipping it up the coast to an onshore receiving facility in northwest Norway. Once there it will be sent via a series of undersea pipelines to three injection wells and injected back into the shale of the Troll oilfield. At present, the project is still in an evaluation phase. Many locations have not yet been finalised, including the site of the receiving plant. When constructed, however, the plan is to create a commercial CCS solution capable of receiving carbon from Norwegian and European sources. The programme will

now begin seeking investment and funding, with a decision to proceed scheduled for the Norwegian parliament in 2019. A wider reach So why is the Norwegian government pursuing CCS at this scale? The Troll project has only recently been proved to be technologically feasible following a series of studies carried our 2016. While there are more than 20 underground CCS projects in development or operation worldwide

Platform leg on Troll A (see cover pic). Picture: Statoil/Harald Pettersen

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September 2017

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already, several of them in Norway, the technology remains underdeveloped and questionably cost-effective. Norway is one of the leading nations conducting CCS, but the Sleipnir and Snohvit CCS projects run by Statoil have been operational for just 20 years. Compared to other ways of cutting carbon, such as renewable energy, CCS lags behind in terms of reliability and profitability. Speaking to NewsBase, head of Natural Gas and Carbon Research at the research consultancy Energy Aspects Trevor Sikorsky suggested that this project might have larger goals and markets in mind than mere domestic industry. “Norway has been running CCS programmes for a while, so I think it’s more a question of consolidating the investment they’ve already made. From a business standpoint, the idea is to roll out CCS as a technology and a pool of expertise that they can sell to others. They’ll be aiming to sell to countries with big coal and gas and fossil fuel infrastructure like China and India. “If you’ve already gone down the road and made an investment in the technology, like Norway has,” he added, “then you’re going to want to keep pushing and try and make some money out of it. That said, I don’t think there’s a massive appetite out there for CCS. Certainly Norway has the potential to operate CCS projects. They mainly use gas-fired power stations, which can be easily captured, and they’ve got the money and political will to run this kind of big project – but with renewables now able to generate a reliable baseload through battery storage and better technology it’s falling behind as a low-carbon solution.” Renewables, not repositories This opinion – that CCS has essentially lost the race against renewable energy as the principle green energy solution – is an interesting one. One of the method’s major drawbacks is that it does not produce any power by itself, instead merely mitigating carbon emissions from existing power plants. While renewable energy was still intermittent and unreliable, this was not a major problem, but advancements in the field of battery storage and the cost-effectiveness of renewable systems have made them much more viable in recent years.

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“CCS used to be the flavour of the month, but it’s really lagged behind other solutions,” Sikorsky continues. “We’ve seen massive uptake of solar and wind power, which to my mind are better solutions than CCS. You don’t have the environmental impacts of fossil fuel mining, you don’t have the environmental impacts of transporting fuel and then carbon around the planet – there’s a lot of good reasons to go down a pure renewables route rather than an adjunct to fossil fuels.” Furthermore, CCS is still comparatively expensive, especially without the economy of scale benefits and reduction in costs that renewables have seen thanks to extensive use and government subsidies. Renewables are also viable on a much smaller scale than CCS projects, with personal-scale projects such as home solar panels and miniature wind turbines being feasible, while CCS is not viable in the same way. There is also the necessity of absolutely gas-tight storage for CCS projects – many underground repositories like the Troll oilfield have been extensively drilled and tapped, meaning that there are many potential leak points. A 1% leak rate will drain the storage in less than 100 years, making the project pointless in a relatively short space of time. No mean feat If it is viable and approved, this project will be a huge endeavour that unites the Norwegian government, industrial and commercial partners for a huge programme of technological, regulatory and commercial development. Collaboration will be essential, especially if Norway wants to develop the required bases of knowledge and technology to sell CCS internationally. One other potential green benefit of this programme is the possibility of hydrogen generation through CCS. Hydrogen extracted from natural gas produces carbon, but if a reliable CCS value chain and the appropriate infrastructure exists it could potentially mitigate the carbon emissions of hydrogen as a fuel source, resulting in carbon-free combustion energy. Effective CCS significantly simplifies the value chain of hydrogen power generation for vehicles and power plants, potentially making it a component of a green power source to rival renewables – if it works. n

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On the radar

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

Sweeter supercapacitors Researchers at Queen Mary University of London (QMUL) and the University of Cambridge have built a prototype polymer electrode which could help aid supercapacitor development. The design, which resembles a Christmas candy cane, is capable of storing energy at close to its theoretical limit, but with the flexibility and resilience of charge/discharge cycling. The technique could be applied to many types of materials for faster device charging. The research was published in ACS Energy Letters. Typically polymer supercapacitors, can only access the top few nanometers below the material surface for storage. Instead the researchers developed a way to interweave nanostructures within a bulk material, thereby achieving the benefits of conventional nanostructuring without using complex synthesis methods or sacrificing material toughness. Project leader, Stoyan Smoukov, explained: “Our supercapacitors can store a lot of charge very quickly, because the thin active material (the conductive polymer) is always in contact with a second polymer which contains ions, just like the red thin regions of a candy cane are always in close proximity to the white parts. But this is on a much smaller scale.

“This interpenetrating structure enables the material to bend more easily, as well as swell and shrink without cracking, leading to greater longevity. This one method is like killing not just two, but three birds with one stone.” Using a technique called interpenetrating polymer networks (IPN) allowed the team to drastically increase the material’s surface area. That also helps solve two other problems. It brings flexibility and toughness because the interfaces stop growth of any cracks that may form in the material. It also allows the thin regions to swell and shrink repeatedly without developing large stresses, so they are electrochemically resistant and maintain their performance over many charging cycles. The researchers are currently rationally designing and evaluating a range of materials that can be adapted into the interpenetrating polymer system for even better supercapacitors. n

September 2017

The ShAPE of things to come Magnesium is 75% lighter than steel and is the fourth most common element behind iron, silicon and oxygen. But auto makers have struggled to incorporate magnesium alloys into structural car parts. Achieving the necessary strength has typically required the addition of rare elements such as dysprosium, praseodymium and ytterbium. Now the US Department of Energy’s Pacific Northwest National Laboratory has developed a process that eliminates the need for these elements, and improves the material’s structural properties. It uses a process akin to extrusion, heating and spinning the element before pressing it into shape to create novel microstructures that are not possible with traditional methods. This also improves ductility, making magnesium easier to work with. The PNNL team designed and commissioned an industrial version of their idea and received a one-of-a-kind, custom built Shear Assisted Processing and Extrusion machine – coining the acronym for ShAPE™. With it, they successfully extruded very thin-walled round tubing, up to two inches in diameter, from magnesium-aluminium-zinc alloys AZ91 and ZK60A, improving their mechanical properties in the process. This significant reduction in force would enable substantially smaller production machinery, and save energy. n

The one who NOx Chemical engineers at the University of Notre Dame have discovered a catalytic process that could help curb emissions of nitrogen oxides (NOx) from diesel-powered vehicles. A study in collaboration with University of Notre Dame, Purdue University and Cummins focused on copper-exchanged zeolites - catalysts used to promote the conversion of NOx into

environmentally benign nitrogen gas. Typically these catalysts work at temperatures too high to capture a large fraction of the NOx produced, however researchers discovered a key chemical step to improve performance at low temperatures. The study was co-authored by William Schneider, the H. Clifford and Evelyn A. Brosey Professor of Engineering in the Department of Chemical and

Biomolecular Engineering at Notre Dame. Computer modelling of the movement of the copper ions within zeolite showed the ions were much more mobile than anyone had appreciated - to the extent they were able to swim through the zeolite pores and pair up. “We hypothesised that this pairing was key to the lowtemperature performance,” said Schneider. Experiments

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performed by the Purdue team at the Advanced Photon Source at Argonne National Laboratory proved that this pairing was happening during one step in the overall catalytic process. The team was able to combine the experiments and computations to quantify the pairing and its influence on NOx removal and believes the process could be used for other catalytic reactions. n

September 2017

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Punchy applications for featherweight material A superlight, super-elastic and electrically conductive “metamaterial” has been designed by researchers at Purdue University. Other properties, including flame-resistance and thermal insulation, infer the substance could have numerous applications, from construction to aerospace. The composite material uses nanolayers of ceramic aluminium oxide in combination with graphene. The graphene scaffold, referred to as an aerogel, is chemically bonded with ceramic layers using a process called atomic layer deposition. Although the constituent parts are brittle in isolation, the material’s honeycomb microstructure provides superelasticity and structural robustness. The composite may make a good substrate material for flexible electronic devices and strain sensors, or as a flameretardant, thermally insulating coating, and thermoelectric devices, according to associate professor in the university’s School of Industrial Engineering, Gary Cheng.

Findings were detailed in a research paper published Advanced Materials. This was produced in collaboration between Purdue, Lanzhou University and the Harbin Institute of Technology, both in China, and the U.S. Air Force Research Laboratory. The process of manufacturing could also

be scaled up for industrial manufacturing, Cheng said. Future work will include research to enhance the material’s properties, possibly by changing its crystalline structure, scaling up the process for manufacturing and controlling the microstructure to tune material properties.n

A breath of fresh zinc-air Researchers at the University of Sydney say they have found a successful solution to one of the hurdles in the development of better zinc-air batteries. These batteries generate electricity via the oxidation of zinc using oxygen from the air. Although some zinc-air batteries are used to power devices like hearing aids, cameras and railway signalling equipment, more widespread use has been limited by the difficulty in recharging. “Up until now, rechargeable zinc-air batteries have been made with expensive precious metal catalysts, such as platinum and iridium oxide. In contrast, our method produces a family of new high-performance and low-cost catalysts,” said lead author Professor Yuan Chen. The team’s new method of catalytic control can be used to create bifunctional oxygen electrocatalysts, allowing new rechargeable zinc-air batteries to be built from scratch, using cheaper and more readily-available elements such as iron, cobalt and nickel. The abstract describes a Zn–air battery produced in the lab to deliver a specific capacity of 756 mAh (representing an energy density of 904 Wh/kg) and a peak power density of 86 mW per square cm. According to co-author Dr Li Wei, these

cells also showed a battery efficacy drop of under 10% over 60 discharging/charging cycles of 120 hours. The hope is that due to the abundance of zinc, larger batteries could be made that are NEWSBASE

much cheaper to produce than comparable lithium-ion batteries, with greater energy density. Theoretically this could reach up to 1,370 Wh/kg – around five times greater than lithium-ion. n

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SPECIAL SUPPLEMENT Pages 13-25

LATE LIFE LEARNING

Thoughts from Decommissioning Practitioners Page 14

A CUT BELOW Laser-powered underwater cutting Page 18

RETROFIT AND HEALTHY

Rotorkâ&#x20AC;&#x2122;s asset management expertise Page 23

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September 2017

Decommissioning: in the OFFSHORE EUROPE

The panel of the Global Late Life and Decommissioning Practitioners session at this year’s SPE Offshore Europe share their thoughts on how innovation and collaboration can drive success in decommissioning

“At the moment, technology is not the driving force, but it inherently needs to be” Caroline Laurenson, Decommissioning Technical Authority at Xodus Group NEWSBASE

N decommissioning, as in everything, failing to plan is planning to fail. For a considerable time, the inherent challenges of shutting down and removing North Sea oil and gas infrastructure have been to some extent neglected, if not ignored. Thankfully, discussions have picked up in recent years, spurred by low oil prices and diminishing production, giving way to a concerted and visible effort to address the imminent prospect of the 100-plus platforms that require dismantling and some 1,800 wells that must be plugged during the next decade. The UK’s Oil and Gas Authority (OGA) has estimated the cost of decommissioning infrastructure on the UK Continental Shelf (UKCS) at just under GBP60 billion (US$77 billion). Yet it has also set an ambitious goal of completing this work for less than GBP39 billion (US$50 billion) – a 35% reduction. Collaborative work done now can ensure that the technology and expertise are available in time to make those cost reductions possible. This is all the more evident in the session time and floor space committed to decommissioning management and technology at the SPE Offshore Europe 2017 conference – in particular the creation of a dedicated Decommissioning Zone and technical programme. This year will see Royal Dutch Shell host a keynote panel session on the topic, together with senior representatives from CNR, Chevron, Heerema Marine Contractors, Marine Scotland and UK regulator BEIS. The Zone itself, supported by sector body Decom North Sea, includes presentations programmed in association with the Industry Technology Facilitator (ITF), The Society for Underwater Technology and the Institute of Mechanical Engineers, as well as leading industry exhibitors such as Diaquip, Integrated DECOM, EMAS Energy and Xodus Group. Independent North Sea operator Fairfield Energy, which is in the process of decommissioning the Greater Dunlin assets, will also share details of its progress.

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zone at Offshore Europe OFFSHORE EUROPE

“It is now a necessity to curtail the consequences of unprofitable assets and wells” Ben Foreman, ITF technology manager In particular, many of these organisations will be participating in a specific session on planning and technology for decommissioning – Decom North Sea: Global Late Life and Decommissioning Practitioners. This panel will set out the view that from approximately ten years prior to cessation of production, operators and contractors must communicate, share the lessons learned from successful operations and ensure that innovative technologies and methodologies are supported to play a key role in the late life and decommissioning sector. ITF will also be running an interactive “Tech Talk” showcasing the challenges and technological solutions now at operators’ disposal. ITF’s session, ‘Well Abandonment Technology Solutions to Increase Efficiencies’, will take place on Tuesday, September 5 at 2.30 pm in the Decom Theatre, and will provide insight on the uptake and impact of technology developments in the industry so far through presentations from some of ITF’s developers. InnovOil spoke with several key presenters from this session to hear their thoughts on how this process could be

“What would have been a lengthy Xxxxxx process ten years ago, is now achievable safely and efficiently” Hari Vamadevan, DNV GL - Oil & Gas senior VP

facilitated and how new technologies could help realise those necessary cost reductions. Curbing costs Certainly, cost is and always will be the driving force behind the industry’s strategy for decommissioning. In other areas of oil and gas, technology has traditionally been able to handle much of the heavy lifting in this regard, with advances usually paying for themselves in the form of enhanced production and greater efficiencies. Decommissioning does not, on the surface at least, offer the same rewards – but innovation must be embraced. Caroline Laurenson, Decommissioning Technical Authority at Xodus Group, noted: “At the moment, technology is not the driving force, but it inherently needs to be driving if we are to see a step change in the decommissioning costs.” However, in order to do that, as ITF technology manager Ben Foreman explained, “New technologies must be able to demonstrate efficiencies in operations, timing and budget.” In areas which have always been plagued by high costs, like NEWSBASE

plug and abandonment (P&A), there now seems to be a consensus that these reductions can only be achieved with serious collaborative effort. Foreman continued: “Well decommissioning in particular has traditionally been done as reverse engineering. Though it is possible, there are potentially costly and complex obstacles in this process, so new technology is vital to fill these gaps. Operators are now realising that the technical challenges associated with P&A and decommissioning need to be addressed quickly to ensure it can be carried out safely and cost-efficiently. Though this type of work is not considered by many to be financially attractive, it is now a necessity to curtail the consequences of unprofitable assets and wells.” In DNV GL - Oil & Gas, senior VP and UK regional manager Hari Vamadevan’s point of view is that the industry is responding to that necessity. Across three joint industry projects (JIPs) the society is involved in, Vamadevan has seen a desire to participate, and not just from technology providers or major operators. “I believe that there is a proactive approach across

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OFFSHORE EUROPE

the supply chain to deliver. I think that the industry is looking at delivering solutions in efficiency throughout the lifecycle of a project and that most certainly includes the decommissioning phase. We only need to look at the first two heavy lifts removals by the massive Pioneering Spirt, where the topside was removed in a single process, to understand that what would have been a lengthy process ten years ago is now achievable safely and efficiently.” Laurenson too pointed to the Design for Decom joint industry project – in which Xodus is a participant along with 12 other organisations – which has identified some key collaborative potential with other projects such as the Ardent project – investigating the removal of subsea pipeline bundles – and Xodus’ own project examining the removal of skirted structures from the seabed. Thinking collectively That is not to say that technology is the only method of cost reduction. Better collaboration and a greater sharing of data and project methodologies can also help to create a much more efficient schedule for service providers and the supply chain. Vamadevan explained: “One of the biggest challenges today is the issue of timing. As decommissioning continues to be deferred on large projects, there is no clear timeline as to when operations will reach the end of their natural and prolonged lives. There is a temptation, therefore, to defer investment in new decommissioning equipment and technologies.” More transparency on this front, and perhaps more decisive action from asset owners, will ensure the resources are in place when the time comes. “The scale of the work to be undertaken is vast,” added Laurenson. “And much can still be done to understand the scope requirements on a collective scale to then optimise how the projects are executed.” Yet a collective approach to scheduling must be balanced with the inherent uniqueness of each asset; as with bringing new fields online, there are few instances where a ‘one-size-fits-all’ approach can be adopted. The solution in this case is ensuring the right expertise is on hand to examine the costs involved in each operation. ITF’s Foreman noted: “A number of platforms and infrastructure were not designed with decommissioning in mind, which adds

complexity. The lower oil price has also meant that income from production does not meet the opex for a field which has sped up the ‘cease in production’ process. Once infrastructure has ceased production, the decommissioning process can begin and operators look at the removal of the asset and the costs associated with it.” Operators who have succeeded in undertaking decommissioning work so far, he says, have been successful because they are constantly improving their work processes. Transparency and promotion of these challenges is also vital. According to Laurenson, “There needs to be more visibility of the technical challenges being faced by the industry. Operators need to engage the supply chain to look for costeffective solutions together and realise the opportunities that technology can bring when the problem is faced and the right minds are involved.” That includes promoting the search outside oil and gas. Both Foreman and Laurenson drew attention to the necessity of technology transfer from industries such as the nuclear, aerospace, automotive and NEWSBASE

medical sectors; ITF in particular is working hard to support that process within its membership. Testing the waters Other barriers may be structural and/or behavioural. The ‘race to be second’ is a well-documented problem for technology developers, and decommissioning is no exception. It can therefore be difficult to encourage asset owners to take perceived ’risks’ with their strategy and adopt new technology when existing methods – even if they are costly or inefficient – are at least known. Laurenson elaborated on this: “There is a dichotomy where operators will say that they are embracing innovation, but when it comes to executing the work they may prefer to stick with tried and tested methods and ‘off the shelf ’ equipment. There may be barriers to technology uptake, for instance, if the contracting strategy does not adequately address the risk/reward profile and how it is partitioned between the operator and contractor.” That hesitance has a knock-on effect for technology developers, especially if it denies

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Selection of pictures from the previous Offshore Europe Conference in 2015 them opportunities to qualify equipment. “There is a further barrier to investment in technology development due to limited financial capital at an individual operator level to invest in research, testing and field trials – especially when that investment may only be applicable to just one asset or a small portfolio,” she added. That is not to say solutions do not exist. Foreman was positive about the contribution organisations such as ITF could make to innovators in search of backing and industry co-operation: “The problem lies within the development process, as it can be difficult for developers to secure opportunities to fieldtest their technology, which means that they never make it to commercialisation. Though the industry is understandably reticent about investment in R&D in the current climate, our members understand the need for new technology. There is also willingness within the operator and regulator community to adopt new technology strategies,” he said. “It is vitally important that any technology facilitator can justify the business case to operators and regulators in order to validate the risks and the development benefits,” he continues. By working with

both operators and developers, ITF offers one route for qualifying these technologies – hopefully meaning it can enter into effective commercial more quickly. Recent ITF request for proposals (RFPs) on well plugging and abandonment (P&A) have included new, enhanced or alternative technologies to cement plugs, improving through tubing logging to verify the quality of hydraulic seals behind tubing and casing and identifying safer, faster and cheaper methods to remove tubing and casing during P&A operations. It will launch another later this year with a broad focus on decommissioning technologies. DNV GL, meanwhile, is a partner in Integrated Decom, a collaboration of companies offering a total, single-source solution which handles front-end planning and preparation for decommissioning and the delivery of an approved decommissioning programme with documentation required by the Regulator. Alongside three partner companies – Costain, Axis Well Technologies and BMT Cordah – this enables operators to take a holistic approach to the problem. DNV GL’s presentation during the Decommissioning NEWSBASE

Zone will discuss the kinds of cost and efficiency savings that can be achieved through a single-source consortium. With a decade’s worth of work to do, the sheer size of the North Sea’s decommissioning is still staggering. But by embracing technology and collaboration, the challenge is far from insurmountable. Events such as SPE Offshore Europe should also demonstrate that technology developers, service providers and operators are up to the task – and that the industry can no longer be accused of failing to plan. n The session ‘Decom North Sea: Global Late Life and Decommissioning Practitioners’ will take place at SPE Offshore Europe 2017 on Thursday September 7, 10.00am12:00am in the Decom Theatre. ITF’s session at Offshore Europe, ‘Well Abandonment Technology Solutions to Increase Efficiencies and Reduce Costs’ takes place on Tuesday, September 5, 2.30pm – 4.30pm in the Decom Theatre, followed by a free decommissioning Tech Talk, held at the Chester Hotel, Aberdeen from 6.00pm.

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New project eyes subsea cutting with laser target

A new laser cutting tool for use underwater could slash the cost of decommissioning

CCORDING to Oil & Gas UK, operators intend to decommission around 17% of pipelines on the UK and Norwegian Continental Shelves (UKCS and NCS) in the coming decade. Around 850 pipelines, running to over 7,500 km, are likely to be removed, not to mention the thousands more steel structures, jackets and other infrastructure requiring removal. Between 2016 and 2025, the group’s forecasts estimate that making safe and decommissioning infrastructure could cost up to GBP1.3 billion (US$1.7 billion) on the UKCS alone. In response, a UK-based project will see the development and demonstration of a low-cost decommissioning technology for working in challenging offshore environments. Specifically, this takes the form of a high-speed, low-cost, robust and flexible underwater laser cutting solution. The primary anticipated benefit of this technology is a reduction in the deployment

time, deck space and operational times required to decommission subsea Underwater Cutting Solutions (UCS), in partnership with The Welding Institute (TWI) and McDermott Inc (MDR), and backed by InnovateUK, is developing a highspeed, flexible laser cutting technology that can be deployed remotely along with options for Diver and ROV. Dubbed SubSeaLase, the project will see the development of a prototype cutting system alongside an underwater laser cutting tool capable of cutting subsea. While the original project brief looked to use lasers at depths of 100m, the objective for the group is now to push to 200m. Speaking with InnovOil by phone, UCS general manager Fraser Collis said that if the system can be proven at these depths, the path to deployment in even more challenging environments becomes much faster: “If we work at sub-200m depths, it will give us enough expertise and experience to take this above and beyond. The end goal is ultradeepwater.” NEWSBASE

Making the cut Mr Collis said that the company was very much at the forefront of bringing new technologies to market. Since its inception in 2004, UCS has designed and patented a wide variety new subsea cutting technologies. Having established itself in three key applications – dredging, cutting and coating removal – the company has continually pushed the envelope, from its first patented dual-cut band saw, through to its recent successes with diamond-wire cutting equipment. Indeed, Mr Collis is confident that, to the best of his knowledge (and from client feedback), the company’s diamond wire cutting systems are “producing the quickest cut times with this type of technology in the world.” In that regard, the company’s foray into laser cutting technology is simply the next logical step, he says. The project, which was begun in September 2016 and runs for three years, pairs TWI’s knowledge of lasers with UCS’ expertise in designing, manufacturing and operation of subsea tooling systems.

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The ability to use the laser – while in water – could reduce cutting times fourfold compared with existing cutting methods

Backed by more than GBP1 million (US$1.3 billion) in funding from InnovateUK, the hope is that a laser tool will add a new and powerful string to the companies’ cutting bow. TWI already has carried out considerable research and development activities into the use of laser technology for decommissioning applications, including laser cutting and laser concrete scabbling (or spalling), which have been used to great effect in sectors such as the nuclear industry. However, deploying these systems in water and at depth brings a new set of challenges. As Mr Collis explains, the project will see the development of a laser and tooling system initially for deployment inside a pile jacket, which will enable cutting to be performed below the mudline. The groups’ future sights are then set on a suite of tooling functions for internal, external methods, ROV and diver operations. The laser itself will be delivered via fibre from a laser source and gas compressor, both of which remain topside. This will provide

laser power of somewhere in the region of 1020kW, he says, well within the capabilities of the vessels from which it would be deployed. Expanding the toolbox Lasers offer considerable benefits compared with contact or abrasive tools; a non-contact laser eliminates the risk of mechanical jamming and tool wear, representing a significant reduction in down-time and the associated cost of parts. Naturally, speed is also a major upside. The partners have suggested that the cutting process could be up to be four times faster than existing underwater cutting technologies. Greater reductions are possible if one factors in the reduced number of working days at sea required to complete a job, or indeed a whole campaign. Once the group has both technology and processes in place in 2019, the goal is then for the SubSeaLase to be developed towards a post-project use, allowing the project partners to “hit the ground running” with a commercial offering, he explains. NEWSBASE

UCS is keenly aware of the benefits that laser adoption can bring to the sector. “UCS has never shied away from any type of new cutting technology,” he says, and as laser power and equipment flexibility increase, he believes that “with the current pressures of cost reduction, the SubSeaLase project will give the industry access to an exciting new advancement in subsea technology, furthering the cutting toolbox.” Just as laser cutting has become accepted onshore in many industrial processes the group is confident it will not be long before the subsea sector can realise its benefits too. n UCS will be attending SPE Offshore Europe 2017 – for more information on SubSeaLase or to speak with a member of the team, visit Stand 2E150 Contact: Fraser Collis, UCS

Tel: +44 (0) 1467 622212 Email: admin@ucsltd.net Web: www.underwatercuttingsolutions.com

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UK regulator outlines North Sea The Oil and Gas Authority (OGA) has advocated that operators adopt different approaches to meet its goal of keeping decom costs below US$50 billion, writes Callum Cyrus

HE UK’s Oil and Gas Authority is as efficient as possible. (OGA) has firmed up proposals Operators are understood to be to ensure industry operators shave able to claim back as much as 50% on 35% from decommissioning costs decommissioning costs, which gives London at end-of-life assets on the UK Continental an interest in keeping the overall bill low. Shelf (UKCS). A recent study by Wood Mackenzie, an According to the OGA’s new cross-basin energy consultancy, had indicated the UK study, the industry will need to spend taxpayer faced a GBP24 billion (US$31 GBP59.7 billion (US$77 billion) at 2016 billion) for North Sea decommissioning. prices to remove platforms and associated Meanwhile, operators are keen for infrastructure. restraint on decommissioning costs to avoid It hopes technological innovations draining their cash flow after a turbulent few and cost-cutting strategies will reduce the years defined by the industry crash. decommissioning outlay to below GBP39 billion (US$50.4 billion), but argued New goals operators must be willing to try “different The OGA said it anticipated 48% of the approaches”. decommissioning spend would fall in the Earlier reports have shown at least 250 Central North Sea region, with the northern UKCS fixed installations must North Sea accounting for a be dismantled by 2050, along further 31%. with 250 subsea systems, 3,000 These two regions will “Investors will pipelines and 3,000 wells. represent almost 80% of need to move The government wants to decommissioning spend away from the before 2025, with the bulk encourage greater efficiency on decommissioning spending focus on cash flow of dismantling in the West to reduce the state’s revenues that underpinned of Shetland (WoS) region shed via tax relief available anticipated beyond 2025. earlier upstream for decommissioning spends. A Maximising Economic It believes operators will be Recovery (MER) framework phases and content with external guidance will be used to encourage embrace new in areas which are ripe for investors to dismantle their technologies or installations in the most costsavings; at stages such as well abandonment, topsides the opportunity effective manner. removal and Cessation of The authority’s MER to co-operate Production (CoP). guidebook states it will with others.” “ensure” decommissioning Integral part plans are drawn up at an The OGA’s ambition is for decommissioning “appropriate” time, while promising to become an integral part of the asset to facilitate better cost projections and management cycle, on the same level as collaborations between licence holders. exploration, development or production. Operators will be told to finalise Early evidence of this came in August decommissioning preparations at least six 2016 when the authority folded its former years before CoP, with an execution and decommissioning unit into an exploration, contracting strategy to follow within three production and decommissioning (EPD) years. directorate. Technological advances are likely to Both the OGA and the industry have a change the course of decommissioning in strong incentive to ensure decommissioning the UKCS, and operators may be required NEWSBASE

to deploy innovative approaches while decommissioning installations. While this might help efficiency overall, however, it could also inflate decommissioning expenditures in the short term. OGA has previously said that operators tend to prioritise cash flow over net present value (NPV). The former objective implies investors might select technologies with the lowest price up front to free immediate cash flow, while the latter is important if the industry and OGA are to meet their target. An OGA spokesperson told InnovOil: “OGA is in a pretty unique position [in] that it has oversight of the whole basin so we see the whole picture. We expect operators to collaborate for sure, but when it’s something like decom where there’s an obvious cost saving then parties are generally going to be quite willing.”

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decommissioning cost target Allseas’ Pioneering Spirit approaches the Brent Delta platform for topside removal, April 2017

calculating decommissioning returns, a formula which plays against new entrants. Another issue is how to ensure operators collaborate across different licences to maximise their efficiencies. Wood Mackenzie believes particular savings could be realised with so-called “batch” decommissioning programmes that group together end-of-life assets by region, operator or play. In September 2015, it estimated that such batch schemes would save operators 20% on average in the central, northern and southern North Sea regions. “We’re helping to get a well plugging and abandonment optimisation campaign off the ground which is along those lines,” the OGA official told Innovoil. “[It’s about] sharing resources and looking from a regional perspective.”

Who pays? OGA’s task widened somewhat with the GBP59.7 billion (US$77 billion) figure, which is higher than previous estimates and thus implies a larger cost-saving target. The estimate is 8.7% more than Wood Mackenzie’s GBP54.9 billion (US$71 billion) projection, though the Edinburgh-based consultancy noted that the “picture is constantly evolving”. Its senior analyst for UK upstream, Fiona Legate, said around GBP5.8 billion (US$7.5 billion) had already been ploughed into UKCS commissioning projects. One issue concerns which stakeholder should bear the burden for decommissioning spends. UKCS operators increasingly tend to be start-ups or private equity vehicles, as major IOCs pare back their North Sea exposure in response to low oil prices.

For example, when Royal Dutch Shell agreed to sell several UKCS assets to Chrysaor for up to US$3.8 billion in January, some feared the transaction could be surpassed by a US$3.9 billion decommissioning bill. There are concerns that new investors might be deterred by these sorts of numbers unless the old operators cover a share of decommissioning costs, leaving end-of-life assets with below-optimum yields. In Chrysaor’s case, Shell agreed to retain a US$1 billion liability for decommissioning its former assets. The UK Treasury also hopes that tweaks to its decommissioning tax regime will help alleviate the concerns of new UKCS investors. According to Tax Journal, the 2017 Spring Budget promised a review to remove the calculation of historic UKCS profits when NEWSBASE

What next The OGA’s determination to steer decommissioning spending is likely to ensure that substantial headway is made over the next couple of decades. Whether this will be enough to fulfil the OGA’s 35% target is far less certain, however, though it is reassuring that the OGA intends to update the industry on its progress regularly. Much will depend on to what extent OGA can encourage operators to employ fresh thinking about decommissioning projects. Investors will need to move away from the focus on cash flow that underpinned earlier upstream phases and embrace new technologies or the opportunity to cooperate with others. Recent acquisitions on the UKCS show that compromises will need to be struck with new entrants to ensure the challenges associated with decommissioning do not deter new investment. The OGA must then prove it can use MER commitments effectively without irking investors by over inflating short-term investment. n

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September 2017

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In safe hands with Rotork Asset management expert Rotork helps operators manage and upgrade their flow control equipment.

ATISFYING the flow control demands of the oil and gas industry with reliable and innovative actuation solutions has been one of Rotork’s major achievements throughout its 60 year history. In addition to the manufacture of electric, pneumatic, hydraulic and electro-hydraulic actuators, instrumentation, valve gearboxes and valve accessories for new plants, Rotork has also gained unrivalled experience of retrofitting manual valves with actuators and replacing actuators on installed valves. This activity began in the company’s earliest years and since the 1960s there has been an area of its business entirely dedicated to these site services. Given its experience over 60 years, Rotork can now offer services encompassing system design, new product selection and procurement, design of controls, system integration with existing programmable logic controllers (PLC), the installation of power, control and instrumentation cabling and cable containment, commissioning and site training as well as on-going asset management. (Retro)Fit for purpose As cost pressures continue, an issue that is becoming more and more prevalent in today’s market is how best to take care of existing plant alongside the advent of new technology. For Rotork, this also raises the question of how best to assist clients and product end-users in managing the change to more modern architectures. In virtually every case, one of the most important considerations is how to successfully integrate new equipment with minimum disruption to normal plant

operations and how to take care of the asset once it has been successfully installed. Using basic valve data collected from site, Rotork can match new equipment to any existing valve requirement, while taking advantage of the more compact dimensions of newer solutions. In this manner, the team can aid installation in the limited spaces often encountered in crowded groups of valves – for example, on offshore and onshore manifold installations. Where access to a valve is severely restricted, safe remotedrive solutions can be engineered, involving extension spindles, pedestals and adaptors, using well proven methodologies and design principles. For controlling actuators, the company provides the Rotork Pakscan two-wire digital control system. This extends retrofitting capabilities from valves in the field to the control room, via a continuous chain of robust, proprietary actuation and control equipment. Designed specifically for the valve actuation environment, Rotork Pakscan provides a direct interface with host control and SCADA systems whilst simplifying the overall control network, optimising actuator functionality and increasing reliability. With Rotork’s intelligent actuation technology, hand held instruments provide a secure, bi-directional non-intrusive link, which is used for setting control parameters, commissioning and data collection. This system performs all the switch setting and commissioning functions that traditionally could only be achieved by removing electrical covers. Using the multi-lingual menu on the actuator display screen, it is quick and easy to commission the actuated valve – with or without mains power. NEWSBASE

Rotork IQ3 non-intrusive intelligent valve actuators on a tank farm installation

The same instrument can then be used to download this data and upload it to other actuators with similar commissioning parameters, simplifying and speeding up the operation, or to download actuator operating information from the actuator’s datalogger to provide vital diagnostic information for asset management programmes. Today, in addition to plant upgrading and automation activities, Rotork offers a complete Client Support Programme (CSP) to maintain and look after existing assets on the client’s behalf. Benefits include increased plant availability through planned technical support, improving product reliability over time and helping to avoid costly unpredicted downtime. Ongoing technical support contributes to increases in availability and reliability, leading to improvements in operational performance. Less time spent on maintenance enables employees to spend more time on productive activity. When supplying products over many years it is important that users have an ability to interchange new solutions with the minimum amount of disruption to their processes. Through its comprehensive expertise and international network, Rotork can ensure any such disruption is minimised – and ensure the plant is running with optimum efficiency. n Rotork will be exhibiting at SPE Offshore Europe 2017 – please visit Stand 1D111 for more information or to speak with a member of the team. Contact: Rotork

Tel: +44 (0)113 205 7233 Email: serviceleeds@rotork.com Web: www.rotork.com

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Staying ahead with Hydra HydraWell’s PWC tooling system can plug wells in a matter of days – saving operators weeks

ITH unrelenting pressure to reduce costs in well intervention and decommissioning, renewed attention is being paid to technologies and innovations which can aid plug and abandonment (P&A) operations. Norway-headquartered HydraWell designs and manufactures a range of intervention, cementing and perforation tools. Most notably in this case, the company has developed a proprietary product suite known as the Perforation, Wash & Cement® (PWC®) system. Using a number of patented tools, this system is capable of plugging offshore wells in just two or three days – considerably faster than the traditional method of section milling. The company was founded in 2010, with an idea that it would be possible significantly to lower the costs of P&A, slot recovery and well repair operations with a more effective and cost-efficient restoration of zone isolation integrity. It found success with its firstgeneration PWC technology – HydraWash – before going on to develop the secondgeneration, HydraHemera system. “The essence of our technology is to enable operators to save huge amounts of rig time as well as to reduce their HSE risk and environmental footprint from not having to bring swarf cuttings topside,” HydraWell CEO Mark Sørheim explained. According to Sørheim, the original impetus came from a call for ideas from ConocoPhillips Norway. “The oil services firm asked the industry for alternatives to section milling when plugging wells with no hydraulic seals in the annulus. HydraWell suggested a system where the plug length

Xxxxx

was abrasively perforated and the annulus debris removed and replaced with proper cement,” he explained. The HydraPerf system was replaced by the HydraWash system using conventional tubing-conveyed perforating (TCO) guns, and the first PWC plug was run late in 2010. Jet set Central to the company’s current operations is the HydraHemera™ PWC jetting system, a multi-part system designed to enable well plugging across multiple annuli, and negating the need for section milling altogether. The system is comprised of two components deployed in a single-run assembly: a HydraHemera Jetting Tool and a HydraHemera Cementing Tool. The former uses a series of jet nozzles positioned at irregular angles to wash thoroughly and remove debris from the annuli, including behind multiple perforated well casings. This clears the area of debris, old mud, barite and cuttings, and spaces the area

The HydraHemera tool system NEWSBASE

with clean mud. Following the jetting, a balldrop mechanism activates the Cementing Tool. Cement is pumped downhole and used in combination with the HydraArchimedes™ tool – a curved rubber-bladed tool which forces cement through the perforations, filling the annulus – to place plugging material in the entire rock-to-rock crosssection of the well. After cementing, the tool will then be pulled above the top of cement (TOC) and the P&A plug tested according to the operator’s procedure. This creates a solid barrier for P&A, or from which to begin a sidetrack well. This one-trip approach is considerably faster than many of the alternative methods, and without swarf or the risk of damage to the blow-out preventer (BOP) associated with milling. Tools are also available for all casing cases. The company is confident of the significant time savings that PWC offers. “It enables operators to plug a well in 2-3 days

September 2017

InnovOil OFFSHORE EUROPE

(Left) HydraWell CEO Mark Sørheim

instead of 10-14 days, which is the average for the traditional section milling method. If the operator requires a rig – a semi-sub or a jack-up – to plug the well, you can multiply the rig’s day rate with 8-10 days. That’s how much an operator would save per well when utilising HydraWell’s HydraHemera™ PWC jetting system,” said Sørheim. In one example at Aker BP’s Valhall field on the Norwegian Continental Shelf (NCS), the operator’s total P&A campaign was reduced from 118 days to 50 through using HydraWell solutions. “ConocoPhillips’ Ekofisk Alpha field was plugged and abandoned almost one year ahead of budgeted time,” Sørheim added. “If you multiply the rig rate with number of rig days saved, you reach some very high figures.” Growing market So far, HydraWell has used the PWC system in more than 200 applications worldwide. P&A is so far the biggest part of the company’s business, but Sørheim

The HydraHemera system as deployed in a well. Here the jetting tool is being used to clean out debris told InnovOil that an increasing amount of operators were starting to use PWC for both slot recovery and annulus pressure remediation operations. While still early days, the response to PWC from industry has been largely positive. “As with any new technology, the market is hesitant at first, but given the huge costsaving potential, almost all operators have been positively curious from day one. As soon as the first few plugs were set, a lot of operators opened the door for us. However, we would not have been where we are today without ConocoPhillips Norway. They encouraged us and gave us the opportunity to demonstrate our technology,” he added. Lately, the UK’s growing decommissioning responsibilities have ushered in a string of new contracts. Centrica North Sea awarded HydraWell a three-year frame contract to provide plug & abandonment (P&A) technology and services for the operator’s “A Fields” in the southern part of the North Sea. That was followed by another in midAugust 2017, when the UK arm of an undisclosed super-major awarded the company a frame agreement to provide technology and services for all of its P&A and well repair operations on the UK Continental Shelf (UKCS). The agreement covers the use of the second-generation HydraHemera system under a three-year agreement, with two additional one-year options for extension. The operator also has a contract option to extend the use of HydraWell’s technology to all of its operated assets worldwide. This builds on the success the company has already had with the tool. “Last year, the client in question utilised our technology on three wells. Afterwards they approached us about entering into a frame agreement. We cannot think of any better endorsement from a client. The fact that another supermajor gives us their seal of approval makes this agreement even more special,” added Sørheim. n HydraWell will be exhibiting at Offshore Europe 2017. To learn more, visit the company’s stand at #1F103. Contact: Arne G. Larsen,

VP Business Development Tel: +47 9802 2965 Email: agl@hydrawell.no Web: www.hydrawell.no

NEWSBASE

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LNG carrier completes maiden NSR voyage

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Sovcomflot’s Arc7-class icebreaker, Christophe de Margerie, has completed its first voyage through the northern sea route

HE world’s largest icebreaking tanker, the Arc7 LNG carrier Christophe de Margerie, has successfully completed its first LNG cargo voyage, delivering a cargo from Norway to South Korea in mid-August. The Sovcomflot-owned vessel departed from Norway’s Hammerfest LNG plant, via the Northern Sea Route (NSR), sailing through the Bering Strait on August 6, fully laden and without an icebreaker escort, arriving at Korea’s Boryeong LNG terminal on August 17, according to stakeholder Total. During the voyage, the vessel set a new time record for an NSR transit of just 6 days, 12 hours and 15 minutes. The Christophe de Margerie is only the fifth LNG carrier to transit the ice-bound NSR waterway, which is only navigable when ice conditions permit, a period which lasts for around 145 days between May or June and October or November. It is the first of 15 vessels planned to service Russia’s Yamal LNG project, where the first cargo loadings are anticipated in October, with commercial production scheduled for 2018. In the winter navigation season of 201617, the Arc7 ice-class tanker successfully passed a series of ice tests. The Yamal LNG developers claimed in an August 1 statement that the use of the NSR from Europe cuts the transportation time to Eastern and Southeast Asian markets in half compared to the use of the traditional route. It has previously indicated that the route can shave 10-12 days off a sailing from the West to Japan, when compared with a voyage through the Suez Canal. The specially outfitted LNG tanker, which has a shipping capacity of 80,000 tonnes, previously started test voyages without cargo in March, although the first company to transit the NSR carrying LNG was Gazprom Marketing & Trading, which took Dynagas’ 145,700 cubic metre ice-class 1A and winterised Ob River vessel to Japan in late 2012. The first cargo loadings at Yamal LNG are expected in October, with commercial production scheduled for next year. At times

when the NSR’s ice thickness exceeds the fleet’s capabilities, LNG will be transported to Europe and then transferred to the conventional route through the Suez Canal. Yamal LNG also said the start of LNG shipments though the NSR with the Arc7 ice-class tankers would help to increase NEWSBASE

cargo turnovers to clients in Japan, China, South Korea and Taiwan and develop navigation in the Arctic Ocean. The 16.5 million tpy Yamal LNG project, led by Novatek and Total, is located in the Arctic Circle on the River Ob estuary, which ices over for nine months of the year. n

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September 2017

COMMENTARY

INCE its discovery in 2010, the Johan Sverdrup field has generated great excitement throughout the oil and gas sector, and especially in Norway. The oilfield, which is located in the Utsira High region, 160 km west of Stavanger, is one of the largest ever to have been found on the Norwegian Continental Shelf (NCS). The reservoir, located at a depth of 1,900 metres, is thought to contain recoverable reserves of between 1.9 billion and 3 billion boe. With several recent finds in new areas of the Barents Sea turning out to be smaller than initially hoped, the successful development of Johan Sverdrup could be a potential saviour for the maturing Norwegian industry. Licence operator Statoil says the development has the potential to remain a major project for the next half century, securing both jobs and national income. Around 70% of the project’s contracts have so far been awarded to Norwegian

companies. It is anticipated that development work for the first phase alone will generate around 51,000 man-years of work for the local economy, with another 2,700 man-years in the production phase. Statoil also believes the development could generate in excess of 1.35 trillion kroner (US$170 billion) in production income over the projected 50-year lifespan. This will contribute 670 billion kroner (US$84.7 billion) to state coffers. The first signs After several years of planning and onshore work, this summer saw the first visible signs of the project emerge offshore. At the end of July, the steel jacket for the riser platform was installed without incident by the Thialf crane vessel, owned by the Dutch Heerema Marine Contractors. Weighing in at around 26,000 tonnes, the jacket – which was built by Norwegian engineering firm Kvaerner at its Verdal yard,

near Trondheim – is the largest and most complex ever constructed in Europe and installed on the NCS. It sits in around 120 metres of water and stretches 140 metres from the seabed, with a footprint measuring 94 metres by 64. Some 24 poles weighing a combined 9,000 tonnes were used to anchor it to the seabed. “This is a special milestone for us, because it is the first visible sign of the field,” Kjetel Digre, Statoil’s project director for Johan Sverdrup, said at the time of installation. “We have already done a lot of work on and below the seabed, and in the time ahead we will gradually become more visible above the sea surface as well.”

As summer progresses the Johan Sverdrup project in the Norwegian North Sea has passed several significant obstacles. Tim Skelton takes a look at how the project is evolving

New milestones at NEWSBASE

September 2017

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COMMENTARY

Besides the riser jacket, Kvaerner and its joint venture partner, American engineers KBR, were also awarded contracts to build two other jackets for Johan Sverdrup, as well as the utility and living quarters (ULQ) topside. The companies say the drilling platform jacket will be completed at Verdal in early 2018, followed by the process platform jacket at the same yard in summer 2018. Work on the ULQ topside is also progressing on schedule at a second Kvaerner yard in Stord, between Bergen and Stavanger. It too is scheduled for completion and installation next year. Drilling platform Meanwhile, Norwegian oil and gas service providers Aibel â&#x20AC;&#x201C; contracted for the construction and assembly of the three Johan Sverdrup Phase 1 drilling platform modules â&#x20AC;&#x201C; has also made significant

progress. The Stavanger-based outfit said the main support frame was completed in early August. The 10,800-tonne frame, the largest ever built at its Laem Chabang yard in Thailand, is now en route to Norway. Later the same month, Aibel also announced the mechanical completion of the 8,000-tonne drilling support module (DSM) at its Haugesund yard in Norway, and of the drilling equipment set (DES) at its Grimstad yard, also in Norway. All three modules will be transported to the sheltered waters of Klosterfjorden, north of Haugesund, to be joined together during the first half of September. The transport barge carrying the completed platform will then be towed back to Haugesund for integration work, after which Statoil staff will test the onboard equipment. Once this has been carried out, the platform will leave Haugesund for on-site installation in June or July 2018. Aibel has also been contracted for the

The jacket for the Johan Sverdrup platform is installed by a Thialf crane vessel

Johan Sverdrup NEWSBASE

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Cost savings Statoil has also managed to realise significant cost reductions as the project has progressed. Its initial Phase 1 development plan foresaw an investment of 123 billion

Meling said Statoil was working to an average break-even price of US$25 per barrel on Johan Sverdrup. In Phase 1 the aim is to break even at below US$20, and at below US$30 on Phase 2. The company is also aiming for an ambitious 70% recovery rate.

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hook-up of the drilling platform once it arrives at Johan Sverdrup. It will connect the platform’s systems to the jacket and two gangways, splice the high-voltage cables, and hook up a temporary hotel platform. As one requirement of its receiving environmental approval, the platform will be powered by electricity generated onshore, removing the need for offshore gas turbine generators and so reducing offshore greenhouse gas (GHG) emissions by 80 to 90% compared to a standard development, Statoil claim. In other developments, permanent reservoir monitoring (PRM) of Johan Sverdrup is being installed, which will mean that 80% of the field can be seismically monitored. Moreover, Statoil has also created a digital twin of Johan Sverdrup, which will help with troubleshooting as well as potential process improvements. To date the project has also been able to boast an almost blemish-free safety record. As of April 2017, according to Statoil, only one incident had been recorded. This involved a cement hose and was not deemed serious. Elsewhere, Statoil has also said that the temperature differences in the reservoir are larger than was originally thought, but this is nothing extraordinary and within levels.

September 2017

kroner (US$15.6 billion), but the company reduced this by over 20%, to just 97 billion (US$12.3 billion) in the final design. One key example of cost reduction is that the Pioneering Spirit construction vessel has a 48,000-tonne lifting capacity, offering the possibility of doing a single-lift installation of the topside. Other savings have been enabled by Statoil’s willingness to share data with the several original equipment manufacturers (OEMs) working on the project. “OEMs and suppliers can’t improve without access to Statoil operational data,” Johan Sverdrup’s technical director, Trond Stokka Meling, told the Subsea Valley Conference in Norway earlier this year. “Better quality assurance also lowers cost,” he added, pointing out that having parts arrive on time meant that the project could stay on budget. Simplification of the technical requirements has also cut the budget.

What next? Assuming all continues going to plan, production is due to start in late 2019. Output during the first phase is anticipated at around 440,000 bpd of oil, rising to 660,000 bpd at peak production. Some estimates suggest plateau production could account for as much as 40% of all oil production on the NCS. Oil recovered from the field will be piped onshore, to the Mongstad terminal in Hordaland. Meanwhile, gas will be transported via the existing Statpipe pipeline system to the Karsto processing plant in North Rogaland. In the meantime, Phase 2 has yet to be sanctioned, but Statoil said it expects to submit its development plan to the government by September 2018. It is anticipated that the second phase will then come on stream by 2022. Statoil’s licence partners in Johan Sverdrup were Maersk Oil, Lundin Petroleum, Petoro and Aker BP. Total’s recent multi-billion dollar takeover of Maersk, however, now gives the French oil giant access to the latter’s 8.44% interest in the potentially lucrative development. n Rendering of topsides according to Johan Sverdrup development plan

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September 2017

WiSub, easySubsea work on pinless project A JIP to design a new subsea docking system would enable faster data transfer and AUV chargingt

ESPITE improvements in the ability of sensors and vehicles to gather data, successfully transmitting it is still a difficult task. The large amounts of information gathered by autonomous underwater vehicles (AUVs) require a sizable bandwidth and power reserve for transfer, and even with a strong wireless or 4G signal, the optimal method is physically to connect to a cabled network (or to wait until the craft is picked up by a human crew and transferred manually). Given that most subsea infrastructure already has cabled connections to shore in place, as well as access to electric power, this presents an optimum solution and would allow AUVs an opportunity both to transfer data and recharge batteries. Yet existing subsea connection systems typically employ conductive pins; these require tight mating tolerances, sealing systems which wear with use and offer limited mating cycles. Technology developers are therefore focusing their efforts on developing new kinds of docking systems with greater capabilities and longer lifespans.

The latest group to tackle the challenge is an international collaborative effort between companies and universities from Brazil, Norway, Poland, Sweden and the UK. The consortium is led by Norway’s WiSub, and includes contributions from Bergen University, DOF Subsea, easySubsea, Federal University of Rio de Janeiro, Kongsberg Maritime, Saab Dynamics, Sonardyne, Statoil, Swire Seabed and Warsaw University of Technology. In particular the project will draw on WiSub’s expertise in pinless power and data connections, and Brazilian firm easySubsea’s experience in wireless underwater communication. The project was first initiated under a call for joint industry projects (JIPs) by the Research Council of Norway and Brazil’s R&D funding body Finep in 2016 – the first time the two organisations have worked together.

WiSub’s existing pinless systems allow for much higher rates of data transfer through seawater than many rival non-contact subsea communications methods, by using the company’s patented high-frequency microwave electronics (as opposed to other methods such as low-frequency RF, inductive or acoustic protocols). Its technology enables wireless transfer rates of up to 100Mbps, and power transfer of up to 48W/24V. Pinless technologies also preclude any galvanic separation, allow for greater freedom of alignment, are immune to seal contamination and offer unlimited mating cycles, making them a strong choice for subsea developments. Bi-directional power transfer will also mean AUVs could be used as mobile batteries. For example, AUVs could be dispatched to charge distributed sensor networks from their batteries. n

Station to station The goal in this case is to develop a pinless docking station capable of bi-directional data and power transfer.

Contact: WiSub

NEWSBASE

Tel: +47 5612 3800 Web: www.wisub.com/ Web: www.easysubsea.com/en/

September 2017

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DNV drives subsea surveillance Classification and verification society develops “remote witnessing” system to aid inspection

ITH cost efficiency still the driving force behind industry innovation, classification society DNV GL has recently developed a new solution for remote surveillance services for subsea equipment manufacturing. Its primary goal in developing the technology was to reduce cost, as well as improve safety for surveyors and increase the flexibility of testing schedules. So-called “remote witnessing” equips technicians with hardware and software that provide remote support or, depending on the type of test and its critical points, a standalone camera system that can be installed to increase savings and flexibility. At the local office, a DNV GL surveyor is connected to the technician delivering technical expertise in a timely manner. “Remote witnessing is a part of other DNV GL operations. With this in mind, it was logical that we look at how remote witnessing can improve both on- and offshore subsea verification,” said DNV GL business development lead Eric Allen, who works in the society’s US-based subsea and wells team. “This is an area where digitalisation can be coupled with existing processes to provide effective verification services resulting in high cost and safety benefits.” Setting trends DNV GL’s surveyors tested the surveillance technology in partnership with Trendsetter Engineering Inc. (TEI) on an HPHT Subsea Capping Stack project. To do this, DNV GL developed specific protocols and optimised the camera and software interface, with the aim of ensuring that remote surveyors can deliver the same level of inspection as if they were on site. That is not to say the solution is limited to this equipment – it is applicable to various types of components and testing. “What sets our remote verification technology apart is that it’s not only first to market but it’s

easily transferable to many applications. The approach itself is being implemented in the offshore platforms, however its application to the fabrication and testing facilities to offer cost savings, flexibility and improved transparency is something that DNV GL is pioneering,” the company explained to InnovOil via email. The initial pilot was a necessary step used to identify gaps and establish a solid foundation of protocols. It also demonstrated that remote witnessing was an acceptable tool that can deliver results for independent surveillance when suitable conditions are met. “The success of this pilot programme improved efficiency and delivered cost savings,” said subsea and wells team head Martha Viteri. “Working together with our industry partners we clearly recognised how this will change the future of surveillance.” As third-party surveillance accounts for a significant portion of a project’s verification costs, DNV believes that this new execution model can offer substantial cost savings NEWSBASE

and improved efficiency by eliminating travel and idle time. “Remote surveillance demonstrates DNV GL’s commitment to drive innovation forward and deliver actual cost savings and faster results (for evidence and feedback) for the benefit of our customers. In addition, this creates a safer way of working for surveyors,” added Viteri. Overall, it said, the industry’s attitude to the project has been “overwhelmingly positive,” and that companies have recognised that these remote programmes can be “a stepping stone towards novel solutions that respond to the need of leaner and more efficient.” In the longer term remote surveillance and similar digital initiatives form part of a larger puzzle that can provide operators with more cost-effective solutions.” We trust that industry will continue to take advantage of all these offerings,” DNV GL added. n Contact: Rachel Carmichael

Email: rachel.carmichael@dnvgl.com Web: www.dnvgl.com

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NEWS IN BRIEF

Gunvor keen to back Equatorial Guinea FLNG The Swiss global commodity trader Gunvor has offered Equatorial Guinea’s state-owned Sonagas funding for its share of the country’s new floating LNG (FLNG) programme. Sources close to the matter told the news agency Reuters that Gunvor, Vitol and Royal Dutch Shell were all bidding for supply from the Fortuna development, with a decision expected later in August. “It is now between Vitol and Gunvor, and Gunvor is the front runner. Gunvor is going to finance the Sonagas 30% equity. Sonagas is very happy with Gunvor as they will also work on building a joint venture to do government-togovernment LNG trading”, a source told Reuters. Gunvor’s proposal will help Sonagas secure the 30% share of the project that was reserved for either the government of Equatorial Guinea or its state-owned energy companies in an umbrella agreement signed with Fortuna in May. In return for its support, Sonagas is likely sign a joint venture deal with Gunvor to export LNG once the plant is up and running. Deals of this kind are still rare in the LNG industry despite being common among oil companies, but the ongoing scramble to acquire medium and long term LNG deals suggests that these deals will become more common. Fortuna’s owners are expected to limit sales of the platform’s output to amounts

sufficient to secure bank financing, in order to have the rest available for trade. The size of Gunvor’s proposed supply deal remains unclear, but the company has landed a number of other similar LNG agreements in growth markets throughout the year, including a tender to supply 60 LNG cargoes to Pakistan by 2022 and a US supply deal swapped from GAIL India. The US$2 billion Fortuna project is expected to come online in 2020, with a projected yield of 2.5 million tpy. Fortuna is led by London’s Ophir Energy, with a 33.8% stake in the development, and is supported by the OneLNG joint venture between Golar and Schlumberger, which holds the remainder of the equity. The project has reportedly received more than US$1.2 billion in loans from Chinese backers, including the China State Shipbuilding Corp. n Edited by Ed Reed edreed@newsbase.com

Toshiba America launches US LNG-focused company TOSHIBA America, the US subsidiary of Japanese conglomerate Toshiba, has formed a new operating company that will focus on the US LNG market.

Fortuna is located in Block R, offshore Equatorial Guinea, in the SE part of the Niger Delta complex

NEWSBASE

The new firm, which is known as Toshiba America LNG (TAL), will build the infrastructure needed to produce US LNG, Toshiba said in a statement. The wider Toshiba group will then market the LNG to regions including Latin America, the Caribbean and Asia. TAL will be one of five tolling customers at the Freeport LNG project in Quintana, Texas, the company said. Toshiba has also entered into a pipeline capacity agreement with Enbridge to bring US gas to the Freeport LNG facility, and with Gulf LNG for tug services. TAL will enter into additional arrangements to facilitate the delivery of US LNG “over the coming months and years”, the Japanese firm said. Takayuki Shibano, who has worked at Toshiba since 1987, has been appointed president and CEO of TAL. Cheryl Roberts was appointed senior vice president and chief financial officer, while Veldanda Rao was appointed senior vice president and chief operating officer at the new company. The first LNG export terminal in the Lower 48 US states, Sabine Pass, started up last year, opening up gas sales from the country to the rest of the world. LNG cargoes have been sent from Cheniere Energy’s facility in Louisiana to receiving terminals in Turkey, Mexico, Chile, China, Japan, India, Jordan, Italy, Spain, Portugal and Malta, among others. The slowdown in economic growth in Asia is also having an impact on Asian LNG demand, meanwhile, pushing North American LNG producers to re-orientate themselves

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as exporters to Europe and elsewhere. Until recently, it was widely thought that tight Asian supply would last until the end of this decade, and many would-be North American LNG producers had been targeting exports to Asia. Cheniere is currently the only firm sending large deliveries of LNG from the US. However, US LNG exports are expected to grow significantly in the next few years, with five terminals scheduled to start operating, in Maryland and on the Gulf Coast, by 2020. n Edited by Anna Kachkova annak@newsbase.com

Guinea started in 2014. The Sankei Shimbun, a major Japanese daily newspaper, reported that Osaka Gas was intending to expand its LNG tanker fleet to 10 by the fiscal year 2020 from the current eight. The LNG tanker fleet expansion plan is part of the gas utility’s efforts to transport more shalebased LNG from the US to its facilities and sales destinations on its own and thereby cut costs, the newspaper said. Osaka Gas is aiming to boost its LNG handling volume to 10 million tonnes by that point, compared with 9 million tonnes in fiscal year 2016 which ended on March 31, 2017, it was reported. Osaka Gas also plans to more than double its LNG sales volume to 2.5 million tonnes in the fiscal year 2020 from a little more than 1 million tonnes in the fiscal year 2016, the paper said. The utility has invested in some overseas LNG ventures, including the Gorgon and Ichthys LNG projects in Australia as well as the Freeport LNG export project in the US. JERA, a joint venture between Tokyo Electric Power Co. (TEPCO) and Chubu Electric Power, imported Japan’s first cargo of shale-based LNG from the US in January. An LNG tanker carrying about 70,000 tonnes of the fuel from the Sabine Pass LNG terminal in Louisiana, which is operated by Cheniere Energy Partners, arrived at Chubu Electric Power’s Joetsu LNG terminal on January 6. n Edited by Andrew Kemp Andrew.kemp@newsbase.com

Osaka Gas to expand LNG tanker fleet by 2020 JAPAN’S Osaka Gas intends to secure two more LNG tankers by the fiscal year 2020 to cope with an increase in imports of the feedstock from the US, a local media report has said. Osaka Gas, based in Osaka City, western Japan, is the country’s second largest gas supplier after Tokyo Gas. The gas utility plans to start importing LNG from the Freeport LNG export project in the US state of Texas as early as 2018. Osaka Gas currently buys in LNG from eight countries – Malaysia, Australia, Oman, Indonesia, Brunei, Russia, Qatar and Papua New Guinea – under long-term contracts. Imports from Papua New

Osaka Gas carrier named LNG Venus

NEWSBASE

Baker Hughes clinches contract for PNG’s first offshore gas field US oilfield services provider Baker Hughes has clinched a deal with Australia’s Twinza Oil to help develop the first offshore gas field in Papua New Guinea (PNG). Baker Hughes will provide a wide range of services to develop the first phase of the Pasca A gas-condensate field. These will include drilling services for the appraisal and development phases of the project and an agreement to supply gas processing, compression, turbomachinery, controls for subsea equipment and installation services, the firm added. The field, which is situated in the Gulf of Papua, is estimated to contain around 93 million boe, Baker Hughes said. An appraisal well is scheduled to be drilled in the third quarter of this year, and a final investment decision (FId) for the project is expected in 2018. Baker Hughes is now part of US conglomerate General Electric, after company shareholders approved a merger with GE Oil & Gas in June, forming Baker Hughes General Electric (BHGE). Perth-headquartered Twinza holds 100% of the Pasca A licence and has submitted a two-

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phase development plan for the field. The first phase will involve initial production of natural gas liquids (NGL), including condensate and LPG, with the reinjection of dry gas before the second phase begins. dry gas will be exported during the second phase. The Southeast Asian country is home to the US$19 billion project PNG LNG project, operated by US super-major ExxonMobil. Earlier this year, the firm increased its resource estimate for the project by 2.3 tcf (65 bcm), representing a 25% increase on the previous estimate. Gas for the US$19 billion project will be sourced mainly from the Hides, Angore and Juha gas fields. Most of the project’s LNG has already been contracted to Asian buyers, with China’s Sinopec set to buy around 2 million tpy. n

Shell’s penguin floater

Edited by Andrew Kemp Andrew.kemp@newsbase.com

Shell to build Penguin floater in China ROYAL Dutch Shell has shortlisted two Chinese yards as the final candidates for building a floating production, storage and offloading (FPSO) vessel for the redevelopment of the Penguin cluster of fields off the UK. As the lead contractor, Fluor of the US will work with China’s Offshore Oil Engineering Co. (COOEC) on the topsides, aligning with the hull builder CIMC Raffles in Yantai China, while the rival contractor TechnipFMC has chosen COSCO Shipping Heavy Industry’s Nantong facilities. In late July, Shell chief executive Ben van Beurden named a few projects that are going to be sanctioned for development, including the Penguin FPSO project off the UK. He said that he expected all of these would come to some form of decision in the next 18 months. Sources declined to name Shell’s preferred bidder but said it currently looked like the price was one of the key parameters on which the decision would be based. It is going to commend it to its 50:50 partner ExxonMobil for the final decision before the award is made in the last quarter. Once the award is made, the chosen contractor will start engineering. However, it will be compensated in case ExxonMobil does not make a final investment decision (FID) on the project. Sources said that the FPSO would be roundshaped, based on the Sevan-400

design, with 400,000 barrels of storage capacity. It is understood that Shell has already done its own frontend engineering and design (FEED) of the floater. COSCO is the world’s leading fabricating yard for the Sevan floater, having delivered six such floaters since 2009, though CIMC Raffles built the world’s first Sevan circular FPSO. The Penguin project is situated in Blocks 211/13a and 211/14, about 150 km east of the Shetland Islands, and has been producing since 2003. n Edited by Ryan Stevenson ryans@newsbase.com

Dresser-Rand to supply equipment for CNOOC projects offshore China The Dresser-Rand business, part of Siemens Power and Gas, was awarded two orders to NEWSBASE

supply power generation equipment for two projects for CNOOC (China National Offshore Oil Corporation). CNOOC is the client for the Penglai 19-3 oil field project and Harbin Guanghan Gas Turbine (HGGT) is the client for the Dongfang 13-2 gas field development project. The Penglai oil field is one of the largest offshore oil fields in China and was discovered in 1999; it’s located in Bohai Bay. The scope of supply comprises two SGT-A30 RB (formerly the Industrial RB211 GT62) power generation trains for the Penglai platform. The Penglai field’s 30-MW ISO power rating SGT-A30 RB turbines represent the first offshore aeroderivative gas turbine packages the Dresser-Rand business sold to CNOOC. The SGT-A30 RB gas turbine is a mature product that offers fast delivery times and is ideal for minimizing project risks. With high output the turbine offers cost-effective solutions for challenging offshore applications. The Industrial RB211 evolved over 40 years of technological advancements and has more than 800 installations worldwide exceeding 37 million operating hours. The Dongfang field, discovered in 2012, is a high-pressure, high-temperature gas field

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located in the South China Sea. The scope of supply comprises three SGT-600 power generation trains for the Dongfang platform. The core components of each train are supplied by the Dresser-Rand business, including an industrial gas turbine, base frame, lube oil system, unit control panel and gearbox. And auxiliary systems such as air intake and firefighting system are supplied and packaged by HGGT. The Dongfang platform’s 25-MW SGT600 trains add to the growing list of offshore power generation references for the SGT-600 turbine. n DRESSER-RAND

Water flooding tech bolsters Bozhong 28-2 output CNOOC’S Bozhong 28-2 South oil deposit had yielded more than 10 million cubic metres (62.9 million barrels) of crude by the end of July as the result of water flooding technology

implemented by the NOC to bolster output. Bozhong 82-2 is part of the Bozhong 28/34 oil cluster in the Bohai Sea, which comprises four deposits that were producing around 39,000 bpd of oil as of 2011. CNOOC owns the cluster outright with 100% interest. In August, the NOC said it had conducted research at Bozhong 28-2 South in 2014 to analyse fluctuating sand flows that had complicated oil extraction, and to develop water injection to stabilise yields. Geological difficulties had disrupted output at Bozhong 28-2 previously; in 2011, CNOOC was forced to halt extraction because of a fault on the mooring system of the Haiyangshiyou 102 FPSO. Bozhong 28-2 South is now said to have encountered greater water discharge from its reservoirs, which suggests output from the deposit is bound to diminish. As a result of EOR techniques, however, CNOOC said it had managed to lessen the anticipated decline by around 2 percentage points. Bozhong’s location in the Bohai Sea makes it a crucial source for oil demand in the populous Bohai Sea Economic Region, which includes several areas surrounding Beijing such as Tianjin and Hebei provinces. For decades, exploration regions such as Bohai had allowed China to satisfy fuel consumption without requiring imports, but the country’s soaring thirst for crude has since made this impossible. Others have worked to maximise drilling efficiency in light of low oil prices. In June, for instance, CNPC announced new well plates had saved costs of 400,000 yuan (US$58,824) at the Dagang Banqiao test probe. n Edited by Andrew Kemp Andrew.kemp@newsbase.com

North Sea P&A startup promises ‘hundreds’ of jobs A new North Sea firm focusing on plugging and abandonment has said that it intends to hire more than 400 workers, and has already made its first acquisition. Aberdeen-based start-up Well-Safe Solutions was launched on August 3, having been founded by a number of North Sea veterans including Mark Patterson, the former CEO of water communication company Nautronix, Paul Warwick, a senior executive at Talisman Energy and ConocoPhillips, and NEWSBASE

Alasdair Locke, co-founder of the Abbot Group. On August 9, the company announced that it would buy the oil service company Intervention Project Management and appoint its founder and managing director, Phil Milton, as its CEO. Patterson said: “The acquisition of IPM gives us an excellent foundation on which to build our business. More importantly, with the appointment of Phil Milton to head up our wealth of expertise and experience, we are firmly on track to establishing our authority and credibility in the market.” To keep costs down, Well-Safe is planning to purchase a complete inventory, including two capping rigs and an intervention vessel, as it aims to avoid the traditional problems faced by small start-ups as scheduling conflicts over hired equipment slow operations. To achieve this, the company is looking for GBP200 million (US$285.6 million) in investment from a number of sources, claiming that it can reduce P&A costs by up to a third. As many older assets in the North Sea begin reaching the end of their service lives, demand for P&A and end-of-operations companies is set to rise. Demand for decommissioning assets is already high – Centrica recently awarded a three-year contract to Well-Safe’s competitor HydraWell to P&A its three ‘A Fields’ in the southern part of the North Sea, and other contracts are ongoing. n Edited by Ryan Stevenson ryans@newsbase.com

Bluestream secures annual IRM contract for Total E&P Netherlands Following an intensive tendering process, Den Helder-based Bluestream has been awarded the 2017 Inspect Repair and Maintenance contract with Total E&P Nederland B.V. for 36 offshore sites. This contract strengthens the position of Bluestream as one of the leading service providers of innovative inspection services to the oil, gas and offshore wind market. The contract is part of a long term frame agreement and is a continuation of the longstanding relationship between Bluestream and Total EP that has been in place since 2009. The work scope covers the subsea inspection of 29 platform structures and seven free standing

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Novotech’s proposed second LNG plant in the Yamal Peninsula

domes on the North Sea Dutch Continental Shelf. Additionally an experienced Bluestream rope access team will inspect structures of the topsides which are at locations difficult to access with standard equipment. With the offshore operations to be completed this summer, Bluestream teamed up with Vroon Offshore Services as her maritime partner utilising the Dynamic Positioning class2 vessel ‘VOS Sugar’. Bluestream will execute the complete inspection and cleaning work in two phases. During the first phase Bluestream’s own fully equipped Inspection Class Seaeye Tiger ROV and the Compact Work Class Seaeye Cougar XT ROV will be used, while a team of qualified inspection divers will be deployed during the second phase . n BLUESTREAM

Novatek aims to cut Arctic LNG-2 costs by 30% RUSSIA’S Novatek has claimed it can cut construction costs for its proposed Arctic LNG-2 plant by 30%, in comparison to the US$27 billion required to build the Yamal LNG plant, also located in the Arctic Circle. “We are prepared to cut Arctic LNG-2 construction costs by at least 30%,” Novatek’s chief executive, Leonid Mikhelson, told Russian Prime Minister Dmitry Medvedev, TASS reported on August 10. Aiming to become as big as Qatar by

LNG volumes produced, Novatek has still to complete the Yamal LNG scheme, its first LNG project, but is already looking at a massive second project, which it intends to locate on the Gydan Peninsula, which juts into the Kara Sea. The adjacent Salmanovskoye (Utrenneye) oil and gas condensate deposit will provide the feedstock gas. The company intends to make an investment decision on Arctic LNG-2 in 2019, and the latter’s first stage is scheduled to be launched in late 2022 or early 2023. Mikhelson said in late July that the Utrenneye field could supply more than 30 bcm per year of gas. “We can plan for three production lines, just as at Yamal LNG, each of them producing some 6 mcm [a year],” Mikhelson said, quoted by TASS. The Novatek head added that each liquefaction line would be installed on a separate ice-resistant platform a short distance from the shore, and some 60 km from the Utrenneye field. Condensate will be extracted at the gas preparation stage, and the finished products – condensate and LNG – will be stored on the platforms for subsequent delivery to clients, Mikhelson said. The first cargo loadings at Yamal LNG are due in October, with commercial production scheduled for next year. Novatek has claimed that the transportation of LNG using the Northern Sea Route (NSR) through the Bering Strait will halve the transportation time from Europe to Eastern and Southeastern Asian markets compared to the more traditional route. n Edited by Joe Murphy josephm@newsbase.com

NEWSBASE

3Bear strikes deal on Permian midstream system DENVER-BASED 3Bear Energy has struck a deal with an unnamed anchor shipper to develop, own and operate a gathering and processing system to serve producers in the Permian Basin’s northern Delaware Basin in New Mexico. The 3Bear system will include over 100 miles (161 km) of pipeline wellhead gathering infrastructure, including infrastructure for oil, gas and water transportation. 3Bear’s plans also include building a crude terminal, central water treatment facility and a 60 mmcf (1.7 mcm) per day cryogenic gas processing plant. The system’s design will allow for expansion and is aimed at accommodating growing output from the Delaware Basin. 3Bear anticipates that the system, which will be located across New Mexico’s Lea and Eddy counties, will be operational in the first quarter of 2018. “The 3Bear system is ideally positioned in the basin and will provide an excellent platform as we continue to expand our assets to serve producers’ growing volumes of crude, gas, and water across the Northern Delaware,” 3Bear’s CEO, Bob Clark, said. “3Bear is well capitalised and able to meet all the needs of producers in this rapidly growing basin,” he added. 3Bear, which has a focus on the development of infrastructure in the Permian and Rockies regions, is backed by global

InnovOil

July 2017

page 39

NEWS IN BRIEF

investment group GSO Capital Partners. The announcement comes as midstream operators in the Permian push to keep pace with growing output. Concerns were raised earlier this year about the possibility of production outstripping takeaway capacity. Amid a number of predictions that output will keep growing in the coming months, such fears over takeaway capacity shortages are likely to keep arising. n Edited by Anna Kachkova annak@newsbase.com

Fluor’s Phosphate Megaproject in Saudi Arabia begins production Fluor Corporation announced that the Ma’aden Wa’ad Al-Shamal Phosphate Company’s (MWSPC) Umm Wu’al Phosphate Project in Saudi Arabia has started production of ammonia, merchant-grade acid and fertiliser. Fluor is providing overall program management services for this $8 billion megaproject, in addition to engineering, procurement and operations and readiness services for various scopes. “As part of Saudi Arabia’s Vision 2030, this world-class project will have a long-lasting impact on the region, as it diversifies the country’s economy and creates local job opportunities for citizens,” said Tony Morgan, president of Fluor’s Mining and Metals business. “After less than four years from the start of the execution phase, we are proud to have partnered with Ma’aden to bring this facility to production. We look forward to continuing our partnership with Ma’aden in developing their next phase of mining projects in Saudi Arabia through our recently signed memorandum of understanding.” Production has begun on diammonium phosphate fertilizer, merchant-grade acid and ammonia. Phosphate serves as a key element in fertilizer for agricultural crops. As one of the largest integrated phosphate fertilizer plants in the world, the facility will help meet global food supply needs by delivering 3 million metric tons per annum of diammonium phosphate and nitrogen, phosphorous and potash fertilisers. n FLUOR

Atwood Oceanics announces contract for the Atwood Achiever Atwood Oceanics announced that one of its subsidiaries agreed to a one well contract at an undisclosed day rate for operations offshore Northwest Africa with Kosmos Energy Ventures for the ultra-deepwater rig, the Atwood Achiever. The new contract will commence immediately following the completion of the well in progress under the existing contract and also includes six one-well priced options. As a result of this contract, the expected earliest availability of the Atwood Achiever is March 2018, assuming

Umm Wu’al Phosphate Project

NEWSBASE

no options are exercised. If all six options were to be exercised, the drilling program would be expected to extend until approximately December 2018. Rob Saltiel, President and Chief Executive Officer of Atwood Oceanics, commented, “We are pleased to extend our drilling operations for Kosmos Energy in Northwest Africa. Kosmos continues to be a valued client, and we appreciate their confidence in the Atwood Achiever.” Atwood Oceanics, Inc. is a leading offshore drilling contractor engaged in the drilling and completion of exploratory and developmental wells for the global oil and gas industry. The Company owns 10 mobile offshore drilling units and is constructing two ultra-deepwater drillships. n ATW

page 40

InnovOil

September 2017

What next …?

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

If HydraWell’s Perforation, Wash & Cement® (PWC®) system could aid your P&A or well intervention operation, please contact VP business development Arne G. Larsen on +47 9802 2965, or via agl@hydrawell.no. HydraWell will also be exhibiting at SPE Offshore Europe 2017 at stand at #1F103 The session ‘Decom North Sea: Global Late Life and Decommissioning Practitioners’ will take place at SPE Offshore Europe 2017 on Thursday September 7, 1000-1200 in the Decom Theatre. ITF’s session at Offshore Europe, ‘Well Abandonment Technology Solutions to Increase Efficiencies and Reduce Costs’ takes place on Tuesday, September 5, 2.30pm – 4.30pm in the Decom Theatre, followed by a free decommissioning Tech Talk, held at the Chester Hotel, Aberdeen from 6pm. For advice on asset management, and how old valves can be retrofitted with new equipment, speak with Rotork Site Services on +44 1225 733200. You can also speak with a member of Rotork’s team at SPE Offshore Europe 2017 – visit Stand 1D111 for more information. For more information on Underwater Cutting Solutions, or the SubSeaLase project, please contact general manager Fraser Collis on +44 (0) 1467 622212, or email admin@ucsltd.net DNV GL’s remote witnessing project can offer substantial cost savings and improved efficiencies in surveillance of offshore equipment. Contact Rachel Carmichael at DNV GL for more information via rachel.carmichael@dnvgl.com

NEWSBASE

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