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Bringing you the latest innovations in exploration, production and refining Issue 57
October 2017
POWER DOWN
EC-OG’s Subsea Power Hub emerges Page 10
WATTS UP
ABB puts 100 MW on the seabed Page 16
THE RIG SHORT
Low prices create a perfect storm for rig owners Page 20
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InnovOil
October 2017
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Inside Contacts:
Media Sales
New insight for CUI
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10-MW production unit
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EC-OG’s subsea turbine
10
Tech Radar
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Shell, ITM to produce hydrogen in Rhineland
Charles Villiers charlesv@newsbase.com
SPH sees commercial launch
Kevin John kevinj@newsbase.com
New technologies from outside the world of oil and gas
Editor Andrew Dykes andrewd@newsbase.com
AM parts gain world-first 14 Safer Plug Company uses 3D printing to miniaturise its pipe tools
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100 MW under the sea
ABB progress on the Subsea Power JIP
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SMD’s deepwater winch 18
Phone: +44 (0)131 478 7000
SMD’s electric 6,000m wind, launch and recovery system
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Higher and drier
The offshore rig market will continue to stall for at least another year
Design: Michael Gill michael@michaelgill.co.uk www.michaelgill.eu
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Fishing for ideas at OWI 24 WFR Tools’ one-trip SOLO subsea P&A tool
Waste not …
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Baker Hughes to reduce gas flaring in Iraq
NEWSBASE
ations Bringing you the latest innov
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A UK consortium is to evaluate inspection tools for corrosion under insulation
Media Director Ryan Stevenson ryans@newsbase.com
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A note from the Editor
in exploration, production
Russia’s LNG export formula 28
and refining October 2017
What’s driving Russian companies to consider LNG projects
Issue 56
Subsea collaboration RGU expands relationship with Japan’s Nippon Foundation
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Prelude mooring completed 33 POWER DOWN
Video shows Shell securing facility
EC-OG’s Subsea Power Hub emerges Page 10
News in brief
WATTS UP
ABB puts 100 MW on the
seabed
Page 16
T THE RIG SHOR owners
Low prices create a perfect
storm for rig
34
Contacts 41
Page 20
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October 2017
InnovOil
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A note from the Editor IN THE oil and gas industry especially, we frequently talk of “the race to be second.” It is always encouraging, therefore, to see innovators celebrating a first – and in this month’s issue, we have a few of those to applaud. From subsea marine engineering firm SMD, we examine a recent project which saw the development of a cutting-edge bespoke winch system, the electric winch in the world with the ability to manage an umbilical with active heave compensation and under constant tension, to an operating depth of 6,000m. In another, the UK-based Safer Plug has developed the first 3D-printed component to receive certification for use in the oil and gas industry. The part – a titanium gateway manifold used in a suite of pipeline isolation tools – has been certified by technical services firm Lloyd’s Register for use downhole, and may hopefully represent the start of a growing trend in the expansion of additive manufacturing in the industry. We also sat down with ABB’s vice president of oil, gas & chemicals for Norway, Jan Bugge, to discuss the electrical engineering giant’s long-running JIP with Statoil, Total and Chevron. This pioneering project qualifies components which will enable up to 100 MW of power to be transmitted subsea, at distances of up to 600 km –
truly revolutionising the way the industry approaches subsea development. Bugge explains more about the project and the innovations behind it inside. Continuing the theme of subsea electrification, and visible on our cover this month, Aberdeen’s EC-OG launches its Subsea Power Hub, a seafloor turbine capable of powering subsea components for years longer than batteries alone. Elsewhere, Ed Reed also looks at the turbulent nature of the current rig market. Low oil prices and low demand have limited prospects for new offshore work, and while there are opportunities to be grabbed via consolidation and collaboration, the cold-stacking of older systems could result in many older rigs never seeing service again. In the intervention market, meanwhile, progress continues apace. We speak with Johnny Hicks of US-based WFR Tools about the company’s innovative tools for decommissioning and P&A, and why the Offshore Well Intervention Gulf of Mexico 2017 conference is the best place to discuss them. We also profile some of the innovation ongoing in worldwide projects, from flaring in Iraq, to progress at Royal Dutch Shell’s Prelude FLNG, and Gazprom’s LNG strategy. We are pleased to present the October issue of InnovOil.
Andrew Dykes Editor
NEWSBASE
InnovOil
New insight for CUI page 6
A UK consortium is to evaluate the best technologies available for identifying corrosion under insulation
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LMOST without exception, oil and gas infrastructure will experience changes in climactic conditions and temperature, and almost without exception that results in the possibility of corrosion under insulation (CUI). Even with the most resistant coatings and insulation, water can seep in and begin to damage the pipework, and that has profound effects on operating costs: historic studies have suggested that CUI is the cause of 40-60% of the money spent on piping maintenance. Outside any permanent monitoring solutions, non-destructive testing (NDT) is the primary method by which pipes and temporary pipe wraps are checked for integrity. However, with a range of technologies available, each with a particular set of advantages and disadvantages, it is not always clear which method may be best for the particular NDT job. A new consortium has set out to tackle the problem. The group – which includes TRAC Oil & Gas, the University of Strathclyde and the Scottish Innovation Centre for Sensor and Imaging Systems (CENSIS) – will audit the tools, capabilities and approaches currently used by industry to look at the steel surfaces of assets which are often obstructed by layers of material. Those surveying assets have a range of NDT methods and techniques at their disposal, but many are ineffective at accurately alerting and calculating the extent of CUI. Instead, most technologies tend to produce an average wall thickness reading where corrosion “scabs” have formed, thus failing to pinpoint specific areas of vulnerability. Recording and interpreting these readings is further complicated by the varying dimensions, materials, locations and accessibility of different oil and gas assets. Alternatively, insulation can be removed – but this requires significantly more time being spent in challenging conditions – potentially even causing minor shutdowns – all of which can make the whole process more dangerous for the technician, and more expensive for the asset owner. After assessing what is available, the consortium will explore how improvements can be made, including the development of
new techniques for accurately identifying and measuring areas of corrosion. On the right TRAC TRAC Oil & Gas technical manager Bill Brown explained: “Inspection is becoming more important as the UKCS continues to mature. We’re at the point now where, against the backdrop of a sustained low oil price, if a platform has to shut down for maintenance, it may never start producing again. We therefore need as much accurate data as possible to make informed decisions. “By taking regular readings on an asset’s condition, we can determine whether they are fit for purpose and operations can keep oil flowing, all within as safe an environment as possible. To do this effectively, we need to take stock of all the technology available, verifying its capabilities and limitations. From there, we’ll be able to look at potential new methods for inspecting the integrity of assets, using non-destructive techniques.” Dr Gordon Dobie, of the University of Strathclyde’s Department of Electronic & Electrical Engineering, added: “Working with TRAC’s team, we’re examining what companies currently do to measure wall thickness, repeating it in the lab on specimens, and trying to develop a standardised approach to getting more accurate information from NDT. We’re validating what the instrumentation is saying about the thickness of walls with a view to filling a real and significant gap in the technology already available.” CENSIS, which brokered the relationship between TRAC and the University, will also provide project management support as the initiative progresses. CENSIS’ Rachael Wakefield commented: “Being able to accurately analyse corrosion under insulation is the holy grail of NDT. This project demonstrates that there’s a real opportunity for oil and gas companies to enhance their offering and tackle some of the biggest problems facing the industry.” The first phase of the project is a feasibility study, the results of which will be shared with wider industry and its stakeholders, including the Health and Safety Executive. n NEWSBASE
October 2017
October 2017
InnovOil
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InnovOil
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October 2017
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InnovOil
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Shell, ITM to produce bulk hydrogen in Rhineland
10-MW production unit will supply Wesseling refinery as operator looks to test new technologies
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S InnovOil has already explored this year, hydrogen technologies are becoming a new target for the oil and gas industry. Whether as a fuel for transport, or more recently in powerto-gas applications, refiners especially are seeing opportunities. Moreover, no longer is steam methane reformation (SMR) the sole means of producing the gas cost-effectively. Major operators are joining the trend. This month Royal Dutch Shell, together with ITM Power, announced plans to install a large-scale electrolyser to produce hydrogen at its Wesseling refinery site, within the Rheinland Refinery Complex. With a 10MW capacity, the unit would be the largest of its kind in Germany and the world’s largest polymer electrolyte membrane (PEM) electrolyser. The project will be undertaken by local subsidiaries Shell Deutschland Oil and Shell Energy Europe, alongside consortium partners ITM Power, SINTEF, thinkstep and Element Energy, all of whom have been invited to the preparation of a grant agreement by the European Fuel Cells and
Hydrogen 2 Joint Undertaking (FCH 2 JU), following a competitive call for proposals. A step into the future At present, the refinery uses approximately 180,000 tpy of hydrogen across its various plant processes. It is currently produced either as a by-product of the refining process or through SMR. The intention is to power the 10-MW electrolysis unit using renewable electricity, with a view to producing CO2-free hydrogen for use in the Rheinland Refinery. “The envisaged hydrogen electrolysis would be a step into the future – opening the door to many new development options for the refinery,” said Shell Rhineland Refinery general manager Dr Thomas Zengerly. “This project would allow us to test new technologies in the refinery context” he added. Its location will also allow the refinery to expand its facilities to supply hydrogen to potential new commercial customers outside the refinery. In a statement, ITM Power CEO Dr Graham Cooley added: “Decarbonising NEWSBASE
hydrogen production in the chemical and refining industries worldwide is potentially a very large market. This pioneering project with Shell aims to demonstrate what can be achieved using our industrial-scale electrolysers which can also use low-cost renewable energy and help to balance electricity grids.” The company has already deployed a number of power-to-gas systems, including a 150-kW installation at an RWE site at Ibbenbüren in North Rhine Westphalia and another at a Thüga-operated plant in Frankfurt. ITM’s modular HGas units are housed in standard ISO containers and are available at power ratings from 70 to 1,030 kW, the largest of which will produce 462kg of hydrogen per day, at 20 bar or 80 bar. Based on those calculations, InnovOil estimates that a 10-MW facility such as Shell’s could produce up to 4.5 tonnes of hydrogen per day, or around 1.6 million tpy (if operating at full capacity), although ITM was not immediately able to confirm these production figures. n
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InnovOil
October 2017
Subsea Power Hub sees EC-OG’s subsea turbine system was launched at Offshore Europe, ahead of new deployment trials backed by OGTC
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UBSEA power and electrification continues to be one of the sector’s biggest areas of research and investment. It is therefore encouraging to see promising technologies make it through the difficult developmental stages, and garner some interest along the way. One such successful technology is East Coast Oil & Gas (EG-OG’s) Subsea Power Hub – a seafloor turbine for powering subsea equipment – which saw its commercial launch at SPE Offshore Europe 2017 in September. InnovOil profiled the Hub (abbreviated to SPH) just over a year ago in September 2016. Devised to meet the challenge of powering subsea equipment economically, and for long periods, it consists of a recognisable template structure, with space for up to three turbines mounted in the centre of the frame. Typical seafloor current strength is around 0.4 m/s, meaning each turbine will deliver an average base-case output of 300 kW per annum, with the largest models producing around 150 kWh per year. Hubs can also be clustered and configured by a distribution network for larger project footprints. An intelligent energy management system (IEMS) optimises battery life by considering the energy available in ocean currents and the repeat performance of the unit in powering the battery system, helping to increase design life far beyond batteryonly systems. While typical subsea battery systems may last a year or so, the SPH can extend operating life up to 5 years, the company says. EC-OG managing director Richard Knox told InnovOil that while an exact cost comparison could not be made between the SPH and battery-only systems – in part because the unit includes the cost of battery storage – the economics were still favourable overall. “The comparison comes into play
when we consider specific situations where the batteries may last only 6 weeks to 2 months for an application. This incurs associated costs, including the significant cost of changing these batteries on a regular basis, including the vessel hire and the associated fuel costs, “Knox said. Out of the lab In April, the first SPH was trialled at a European Marine Energy Centre (EMEC) test site in Shapinsay Sound. This prototype used a hybrid drive system, linked directly to a lithium-based energy storage system. The unit ran autonomously as part of its NEWSBASE
test programme over the summer months, with monitoring data sent back to the centre wirelessly for analysis. Knox said that the system performed as planned. He added: “We were happy with how closely the system was performing with what we had predicted. It was really useful to have the system mounted on [the] seabed in an uncontrolled real-life environment. We were able to take the system out of the lab to being fully operational on the seabed.” The data from the EMEC test will now be used for further optimisation. It also provided valuable information on how the different units might perform, he
October 2017
InnovOil
commercial launch The Subsea Power Hub is deployed at EMEC, Orkney
said. “At present, following these tests, we have a better understanding of how we can use the different configurations (either the single or the triple unit). This information and data has helped us to refine the sizing of the units for different applications.” That data also helps the company predict the energy requirements of its potential clients: “Our web application, which was used as a market research tool at Offshore Europe, has allowed us to refine our offering specifically to client needs by using real live results. The use of this data means that we can confidently provide the energy needed for a variety of applications.”
Interest in those applications is growing. As the industry begins to embrace the potential of subsea electrical power, EC-OG is well positioned to take advantage. Knox commented: “Subsea electrification is no longer being perceived as a radical or novel method. It is now seen as something that can be adopted in the near term and for EC-OG this is an immediate reality.” “We’ve seen companies that have been testing fully electric trees for a long period of time. The economics of this are now becoming more attractive, especially within the context of the low oil price environment. The risks associated with adopting the NEWSBASE
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technology are reducing as well. It feels like we are on the cusp of a more general adoption of a fully electrical system for use in wells,” he continued. Knox identifies two distinct sets sub-sets of subsea electrification: the fully electrified “subsea factory” concept, and applications in marginal fields where electricity is used for very distinct applications. Although one requires large amounts of power and the other small, the two should act as complementary disciplines. He added: “The more that we can implement electrification in the small pools scenario then that helps the further use of the building blocks for the subsea factory. An intermediate step is created where learnings from low power networks can be transferred to high power, long distributed networks. This helps build a reliability database. I think that this will be the way that people will exploit fields moving forward.” Deployment decisions EC-OG is now undertaking FEED work for a North Sea field trial, backed by the Oil and Gas Technology Centre (OGTC) in Aberdeen. The work will focus on the in-place SPH design, optimised deployment procedure and de-risking the installation and operational phases. Knox explained: “Installation of the SPH is a very important part in the successful functionality of the system. We are interested in finding out the best way this is achieved technically as well as the associated costs of doing so.” The study will focus on key installation factors such as necessary vessel requirements, overall costs, installation analysis, diver safety and recovery of the system at the end of the life cycle. “This will allow us to have an accurate holistic view of the overall life-cycle cost,” he added. The priority being placed on subsea electrification marginal field development suggests that the SPH could easily find a secure home in the wider subsea power toolbox – and as oil and gas operators look for greener, cheaper and more reliable systems, this innovation ticks all the right boxes. n Contact: Graceann Robertson Tel: +44 (0)1224 933 301 Email: info@ec-og.com Web: ec-og.com
InnovOil
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On the radar
What caught our attention outside the world of oil and gas this month
Two-way mirror Scientists at Imperial College London have tuned nanoparticle arrangements to create a filter that can change between a mirror and a window. The material could enable new kinds of optical filters and possibly miniaturised sensors. The layers of precisely arranged gold nanoparticles were made by applying a small voltage across the interface between two liquids that do not mix. This layer can be dense or sparse, enabling it to switch between being a reflective mirror and a transparent surface. Study co-author Professor Joshua Edel, from the Department of Chemistry at Imperial, said: “It’s a really fine balance – for a long time we could only get the
October 2017
Your biggest fan Rolls-Royce has set a new record for the world’s most powerful aerospace gearbox. Speaking at the International Society for Air Breathing Engines (ISABE) conference, the company’s CTO, Paul Stein, confirmed that the Power Gearbox had successfully reached 70,000 horsepower while on test at Rolls-Royce’s dedicated facility in Dahlewitz, Germany. The Power Gearbox will play a central role in the company’s next-generation UltraFan® engine, helping to deliver improved efficiency over a wide range of thrusts. The Power Gearbox is designed to run to 100,000 HP and future demonstrators are expected to achieve these levels. When running at maximum power, each pair of teeth on the gearbox will transmit more power than an entire grid of Formula 1 cars between them. The associated improvement in efficiency and reduction in weight will allow the UltraFan engine to offer a 25% fuel efficiency improvement over the first generation of Rolls-Royce Trent engines. n
nanoparticles to clump together when they assembled, rather than being accurately spaced out. But many models and experiments have brought us to the point where we can create a truly tuneable layer.” The distance between the nanoparticles determines how different wavelengths of light are reflected or pass through. But unlike previous systems that used chemical means, this process is reversible. Co-author Professor Anthony Kucernak, from the Department of Chemistry, commented: “Putting theory into practice can be difficult, as one always has to be aware of material stability limits, so finding the correct electrochemical conditions under which the effect could occur was challenging.” n
Candied carbon supercaps Drexel University researchers have created a “fabric-like material electrode” that could enable the manufacturer of safer, faster batteries and supercapacitors. The group has designed a new supercapacitor, which looks “like a furry sponge infused with gelatin”, and offers an alternative to the flammable electrolyte solutions that can cause battery malfunction. Designed by College of
Engineering Professor Vibha Kalra and her team, the device uses a thick ion-rich gel electrolyte absorbed in a mat of porous carbon nanofibre to produce a solid device. The design was published in a paper in the American Chemical Society journal Applied Materials and Interfaces. In addition to being nonflammable, the group claims
that the design is more durable and offers greater energy storage capacity and charge-discharge lifespan than current, comparable devices. It can also operate at temperatures as high as 300°C, making it suitable for use in hotter or more hazardous environments. The key to the device is the fibre-like electrode framework. This was created using a process called electrospinning, where a
NEWSBASE
fibrous mat is created by being extruded through a rotating electric field — a process that apparently resembles making candy floss. The ionogel is then absorbed in the carbon fibre. The next step for Kalra’s group, Drexel says, will be to apply this technique to the production of solid-state batteries, as well as exploring its application for smart fabrics. n
InnovOil
October 2017
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Down the tubes Researchers from Northeastern University in Boston have successfully used carbon nanotubes to desalinate water molecules. In a paper published in Science, the group describes how nanotubes of a certain size – 0.8 nm – will only allows one water molecule to pass through at a time. This single-file line-up disrupts the hydrogen bonds within the water, so it can be pushed through the tubes at an accelerated pace. In addition to being the right size, carbon nanotubes also have a negative electric charge, meaning they will repel the negative ions in salt, as well as other unwanted particles. Co-author Meni Wanunu, associate professor of physics at Northeastern, and post-doctoral student Robert Henley collaborated with Aleksandr Noy at the Lawrence Livermore National Laboratory in California to conduct the research. “While salt has a hard time passing through because of the charge, water is a neutral molecule and passes through easily,” Wanunu said. Noy’s lab had previously suggested that nanotubes could be designed for ion selectivity, but it did not have a reliable system of measurement – this is where Meni’s team could step in.
The result is a novel system that could have major implications for the future of water security. Their study has shown that nanotubes are better at desalination than any other existing method, natural or man-made. The two labs have now partnered with
a water purification organisation based in Israel. And the group was recently awarded a National Science Foundation/Binational Science Foundation grant to conduct further studies and develop water filtration platforms based on their new method. n
Can do Defence and technology conglomerate Lockheed Martin has unveiled a new unmanned drone system that can be deployed from a canister. Dubbed “OUTRIDER”, the drone is a mere four inches (101 mm) wide and weighs just 1.7 kg. It is designed to be used in environments where conventional, larger unmanned air systems would not be practical. It was developed at Lockheed Martin UK’s Havant facility in partnership with Wirth Research. Launched via canister at the press of a button, the UAV can be operated remotely or has the ability to be autonomous. Although small, OUTRIDER can travel at up to 50 knots (93 kph) and carries several visual payloads, including an HD image feed TV and infrared camera. Lockheed says this enables potential military, civil or commercial applications. Lockheed Martin UK plans to offer it to market both in the UK and to export customers. “We’re excited and very proud of our collaboration with Lockheed Martin UK
on the OUTRIDER project,” said Nick Wirth, CEO and Wirth Research founder. “Performance enhancement and innovation are fundamental to our motor sport heritage at Wirth Research. Transferring this approach NEWSBASE
from racing, combined with our rapid concept development and aero expertise, has been key to successfully meeting the technical challenges set by the Lockheed Martin team. OUTRIDER is the leading edge result.” n
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InnovOil
AM parts gain world-first oil and gas certification
October 2017
Tim Skelton reports on the 3D printed innovation that has allowed the Safer Plug Company to miniaturise its pipe tools, with the help of Lloyd’s Register
A
DDITIVE manufacturing (AM), or 3D printing as it is more widely known, is by no means a new concept, even if the oil and gas sector has to date been comparatively slow to adopt the technology. But that process could be about to accelerate, with September seeing the establishment of a new certification process and the first metallic AM part certified specifically for use in the industry. With the obvious benefits it offers, it is no surprise that 3D printing is becoming an increasingly prominent feature in many people’s lives. Some have even hailed it as a ‘new industrial revolution’. Unlike conventional manufacturing, objects are built from scratch, layer by layer, rather than by forming them or machining them from a larger block. Ground plastic – or in the most recent example, metal – powder is ‘welded’ first to a template and then to itself by laser in order to form the required product. This allows components designed using computer CAD packages to be built to very precise specifications, within a much shorter timeframe, and with far less waste of materials than standard techniques, all of which helps to slash costs. In some cases, the technology can reduce the time taken to bring products to market from several years to a matter of months or even weeks. Despite all the flexibility it offers, the oil and gas industry has until now been
reluctant to jump on the bandwagon. The latest certification framework, “Guidance Notes for Additive Manufacturing of Metallic Parts”, developed by London-headquartered engineering, technical and business services company Lloyd’s Register (LR) and produced in collaboration with The Welding Institute (TWI), could encourage a change in attitude. Why certify? When LR analysed AM technology it recognised a massive potential for rapid growth within the oil and gas industry. Inspired by this, it set out to produce a set of guidelines to safeguard and guarantee the technology, and to give companies the assurance they need that metallic AM parts can be used safely. According to the group, there are several reasons why such a certification scheme is essential. First, it points out that for offshore products, existing standards cannot be safely applied to the AM process. Metallic AM is similar to welding on a micro-scale, but the control systems and lessons learned from welding are not directly transferable. Moreover, the use of a powder feedstock, new controllable processing parameters and pre-heated parts all result in the need for new design and manufacturing requirements and recommendations. The precision of AM technology is also likely to see existing simpler, but worn-out, components being replaced with far more structurally complex NEWSBASE
designs with potentially inaccessible internal features. A second incentive for having dedicated guidelines is that while tests have proved AM parts to be similar in strength to conventional parts, their ductility and fatigue performance can suffer. This is a particularly critical issue in the oil and gas sector, as the parts are often needed for safetycritical applications and are used in harsh conditions, where there is a risk they may fail to meet minimum requirements. A guided, certified approach to design and manufacture gives end-users confidence in the safety of the components without the need for a ‘belt and braces’ approach with an unnecessarily conservative design. Guidelines also ensure part quality and repeatability. LR sees its certification system as a “stabilising force” in an emerging and fastdeveloping new industry. With innovative AM technologies and new businesses appearing all the time, there is pressure on suppliers to cut costs in order to gain a competitive edge. Moreover, the scale of products required for the oil and gas
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Left to right, Safer Plug’s gateway manifold is shown in various states of manufacture, from transparent stereolithographic prototype, to additively manufactured in titanium and in various states of machining
The gateway manifold is shown inside Safer Plug’s assembled pipeline isolation tool
sector means that large-format printers are needed, and these machines may not yet be ready to make key structural components. Certification again brings reassuring guarantees about quality and safety. The first part The first new component for the oil and gas sector to reap the benefits of LR’s guidelines and receive certification was unveiled in early September. The part is a titanium gateway manifold, designed by British-based Safer Plug Co. (SPC), and built using powder bed fusion by AM production specialists, 3T RPD. It is designed to be included in an assembly for a suite of pipeline isolation tools, which also features the world’s smallest tool suitable for deployment in a six-inch (152-mm) diameter pipe. According to the designers, the manifold’s complex internal channels meant it could not have been manufactured using traditional techniques. Knowing that it would need independent assurance of the innovative new part’s manufacture, design and production, SPC therefore contacted LR in 2016. Using its framework guidelines, LR was able to
monitor and oversee the entire process, assessing not only the materials, but also the manufacturing process and the manufacturing plant itself. “In taking on this initiative, LR’s Additive Manufacturing group has truly opened a gateway to the future,” SPC technical director Ciaran Early told the press when the part was unveiled. “LR’s pivotal role is to guide suppliers through the codes, standards, controls and best practices to manufacture AM parts, in order that end-users will have full confidence that [a] part meets the required level of criticality.” What next? SPC says it wants to set an industry example by demonstrating how oil and gas can reap the benefits of AM. Lloyd’s Register will certify the next batch of 10 manifolds, and is working with SPC to develop a Type Approval certificate. This would allow it and 3T RPD to produce both the manifolds and the pipeline isolation tools on demand. LR says its step-by-step certification process will provide both the oil and gas NEWSBASE
industry and its customers with confidence in the safety, repeatability and quality of complex metallic AM components and equipment. This in turn should boost the adoption of the technology by the sector, and lead to the certification of many more quality-engineered components in future. “As with all things new in O&G, the operators want to be ‘first to be second’ when it comes to novel technologies,” LR global product launch manager Andrew Imrie told InnovOil via email. “Although many organisations are not openly advertising the fact they are working with AM, we know a number of high profile O&G organisations are at advanced stages of assessing and developing AM for a variety of uses. LR’s role in this is consistent with our approach now for more than 250 years, which is to provide an independent method of assurance for novel technologies in the industrial manufacturing area.” At a time of low prices, the cost savings and gains in efficiency that this could offer will go some way to helping beleaguered oil companies regain some of their commercial advantage. n
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October 2017
ABB discusses progress on the Subsea Power JIP, a plan to put 100 MW of power on the seabed by 2019. Andrew Dykes reports
100 megawatts
E
LECTRICAL engineers are used capex savings for one target project alone, by to big numbers. While it may be no allowing the operator to link eight loads via a small feat to move hundreds, even single cable, at distances of around 200 km. thousands of megawatts around from “The project has two main phases,” said power plants to substations and load centres, ABB’s vice president of oil, gas & chemicals it would be difficult to argue that any of it is for Norway, Jan Bugge. “The first was to bring out of the ordinary. Doing so on the seabed, the technology to [technology readiness level] however, is another feat altogether. TRL 2. Having started in 2013, we focused In 2012, as part of its vision for the “subsea on the concept and technology development factory” of the future, Norwegian NOC Statoil of components, so that we could mature the launched a study to investigate how enough concept – that stage we passed in April 2015.” power could be supplied to the seabed to With that milestone behind them, the make that a reality. Given ABB’s expertise in group is now is now working on the formal subsea power – it introduced the world’s first qualification of the components that go into subsea transformer in 1999 – it the various drives, switchgears was a natural fit for the project, and assemblies, before the and together with operators overall system is put Total and Chevron, formed the through its paces. If all Statoil-led Subsea Power joint goes to plan, these industry project (JIP) in early systems should 2013. reach TRL 4 by At present, the majority of 2019. subsea AC power is provided from a platform or topside, Handling the and carried to equipment via pressure multiple cables. It frequently The overall “It’s a bit like means multiple topsides are system ABB has sending a satellite designed works needed, at considerable cost, all of which must be located up, once it’s up with an input of within around 50 km of the 16/50/60 Hz, and there it’s very infrastructure itself. Siting typical transmission hard to get at” voltages of 36-145 power infrastructure on the seabed itself would therefore Jan Bugge, ABB kV. For distances above offer big reductions on topside 250 km and up to the 600 capex and opex in terms of km desired, the low 16.7Hz staffing and maintaining them. frequency is used to ensure transmission. It is here that the big numbers emerge. As stated, the system has three main areas of Statoil’s goal was to transmit 100 MW of innovation: VSDs, switchgear and controls/ power over distances of up to 600km, and low-voltage distribution. Each component depths of up to 3,000m. Those installations not only needs to be pressure-resistant and also had to be reliable enough to function thermally efficient – using natural convection for 30 years with minimal interventions. to cool VSDs housed in oil-filled, pressureTo achieve this, the US$100 million project compensated containers, for example, is not would see the design of entirely new the same as cooling drive units onshore – but equipment, including medium-voltage also reliable enough to run for years at a time. switchgear, variable speed drives (VSDs) These high-power units are “at the forefront as well as associated control systems and of technology,” Bugge said. low-voltage distribution. Yet in doing so, “They have to have redundancies and Statoil said at the time that it expected to monitoring to a totally different level from be able to realise around US$500 million in topsides,” he added. “These are the frontiers in NEWSBASE
a way – understanding the physics of thermal and electrical issues, pressure-compensated designs and high reliability to minimise intervention.” Understanding the thermal and electrical properties of this equipment at pressure is a challenge in itself. ABB is already using accelerated testing to simulate a 30-year working life – processes which then inform component choice and design. “We’re making a lot of, I would say, ground-breaking designs
ABB Subsea Variable Speed Drive
InnovOil
October 2017
page 17
s under the sea to make sure we get that reliability, because that’s the biggest aspect of this,” he continued. “It’s a bit like sending a satellite up, once it’s up there it’s very hard to get at – the same when you put things on the seabed. There are no service engineers at 3,000m.” Achieving reliability over that lifespan also means adding multiple levels of redundancy. “You not only typically have several compressor trains, but we also have redundancy in our own equipment – redundant A-side/B-side controls and low-voltage distribution, as well as in the drive,” Bugge added. The drive units too are comprised of a cell-based structure, allowing the system to bypass specific cells if anything malfunctions or fails. This flexibility also allows variable levels of output. To drive high-power equipment
such as compressors, two or three VSD units can be paralleled to drive 12 or 18 MVA loads. By mounting these on a subsea frame, designers have also been able to save on connectors, using just one 3-phase input and output for the combined VSD. The control and low-voltage distribution systems have similar flexibility. Standard oil-filled subsea control modules (SCMs) and nitrogen-filled, low-voltage subsea electronic modules (SEMs) have been used to ensure a familiar form and allow deployment via moon-pools, but each module is also individually retrievable and offers dualredundancy.
Next steps With the fundamentals understood, the first prototype units are now being built. “We have built the first drive, it has been demonstrated to our key partners, and it was demonstrated to our partners in June in Turgi, Switzerland, where our mediumvoltage drive factory is,” Bugge explained. “The next milestone will be in November, when the first shallow-water tests of the 65-tonne drive unit will be conducted at our ABB facility in Vaasa, Finland. Subsea MV Here, power will Switchgear be circulated from the grid, through the unit and back as part of a “power in the loop” test. This will be run for several weeks, before the project partners meet again for a workshop on the results. In 2018, the project moves into the home straight, with several 3,000-hour tests planned, in order to qualify the units to the desired TRL 4. NEWSBASE
These include a 3,000-hour pressure vessel tests to simulate the operating conditions of power cells at 300 bar, emulating 3,000m water depth. ABB aims to complete these by around April 2018. The project will culminate towards the end of the year with a system test. This will involve two drives, one switchgear and associated control modules – representing a complete subsea transmission system – tested in shallow water, again over 3,000 hours. If all runs smoothly, this should conclude the JIP with TRL-4 proven technology by 2019. Although the geographical spread of the project partners infers that the initial deployments of the technology will most likely be in the Norwegian Continental Shelf (NCS), North Sea or Gulf of Mexico, Bugge says that the technology will be equally applicable throughout the offshore market, including regions like East Asia and Australia. Having been under development for almost five years, the scope of what the JIP has already achieved is not small. Moreover, Bugge says that the potential gains from highpower subsea electrification have ensured backing from operators, even though low prices had made times tough. “This is in a way a game-changer which allows them to put new technology to use, and which will help them to produce more efficiently,” he noted. 2019 is still a way away, and there are many tests left to run. But with the future of offshore oil and gas production undoubtedly lying in fully electrified subsea facilities, the achievements of ABB and its partners over the next few years are certain to have profound implications for the future of the technology, and of the industry. n Contact: Rita-Wei Fu
Tel: +47 2287 2673 Email: rita-wei.fu@no.abb.com Web: www.abb.com/oilandgas
page 18
InnovOil
SMD launches world-first 6,000m winch
October 2017
SMD has built a bespoke electric 6,000m wind, launch and recovery system for Shanghai Salvage
H
YDRAULIC winches may have their advantages in terms of brute strength, but new improvements in technology mean that their electric cousins are quickly closing the gap. Moreover, electric systems have no requirement for large oil tanks, are remarkably quiet and consume very little power from the vessel whilst idling. One company leading the charge is Soil Machine Dynamics (SMD), a major innovator in remote intervention equipment. Most recently, SMD completed work on a bespoke electric drive dual-purpose winch and launch and recovery system (LARS) to accompany an order from Shanghai Salvage for an SMD Quasar work-class ROV. As SMD explained to InnovOil, however, this is the first such system in the world with the ability to manage an umbilical with active heave compensation and under constant tension, to an operating depth of 6,000m. The company, also known as China Ocean Engineering Services Shanghai, will be deploying the LARS and ROV for deepwater salvage operations around the world. The winch will be provided with two interchangeable drums, SMD said: one spooling a 6,000m lightweight umbilical cable, and one 3,000m cable with TMS, which is capable of carrying heavier loads. These drums can be swapped whilst on the vessel to suit the requirements of the mission, without the need to return to shore – offering considerable savings in terms of time and expense. The integrated launch and recovery system, comprising the A-frame and winches, has a safe working load of 12 tonnes up to Lloyds Sea State 6, requiring a design load of 2.5 x safe working load (SWL). The winch can pull up to 12 tonnes on the top layer when in 3,000m TMS mode, and the pull is limited when operating with the lightweight 6000m system. Time is also saved in outfitting the vessel, as the integrated electric drive suite allows the entire system to be quickly mobilised
onto a vessel of opportunity as one unit, via a single point lift. Moreover, the design can be integrated with the vessel’s electronics, meaning energy from the winch can be regenerated and used for other applications on the vessel. Electric avenues The winch itself can operate using either AC induction or advanced synchronous reluctance motors. ABB’s SynRM motor technology also helps ensure compensation accuracy and response time, meaning the ROV can be safely launched and recovered during rough seas. SMD is also providing a PLC control system, featuring auto-depth capability and power loss protection, as well as condition monitoring, remote diagnostics and data logging via cloud-based systems. The Quasar, meanwhile, is a 3.5-tonne ROV capable of carrying payloads of up to 250kg and working at depths of up to 6,000m. Its isolated hydraulic system can run high-power tools, making it a sound choice for salvage operations, and a large payload capacity allows more tools to be carried to the work site, cutting down on additional trips. SMD’s managing director of deck equipment, Paul Hatchett, explained to InnovOil: “Thanks to improvements in technology, electric winches are becoming an increasingly viable option. Electric drive technology for use in marine winches already exists and naturally improves as kit gets smaller, cheaper and offers better performance. In this case – with Shanghai Salvage – the existing offerings on the market would not meet the dynamics demanded for the application with dual drums.” In designing the system, he added, it was not the length of the umbilical that proved a challenge, but rather the delicacy of the lightweight umbilical and the need to control this in an active manner. SMD’s approach NEWSBASE
reduces shock loading on the lighter umbilical, whilst simultaneously meeting the requirements for handling the heavier armoured umbilical. Nearly all existing approaches regulate tension with a system that applies its control in a continuous single direction, where motors are generally running near to or at their most efficient speed (usually around 1500 rpm). Such single-direction systems are able to use reactive feedback, and react the loads to data after it is collected. In this application SMD needed to develop a system which actively changes tension on the fly, as data is collected, and which would apply control setpoints in a predictive manner. “The application not only requires handling of a delicate umbilical, it has to do so in an unstable marine environment accounting from the pitch and roll of the waves as well as maintaining a constant tension on the umbilical to avoid slack,” Hatchett said. “This
October 2017
InnovOil
page 19
Left: SMD’s bespoke winch system
Below: SMD Quasar Work Class ROV
need translated into a forward and reversing drum operation at next to zero rpm, therefore demanding very high torque varying in direction. This is a challenging operating condition for any motor.” Recent improvements in motor technology proved to be the turning point in the design. “Synchronous reluctance motors were selected instead of servo or asynchronous motors, which also reduce wear, service intervals and the need for spare parts,” he said. “A big advantage with this system is that we can apply ‘online’ changes to the fundamental operation; hydraulic systems inevitably need some mechanical hands-on to either increase or attenuate performance, whereas with our electric winch we can adjust performance without having to visit the equipment,” he continued. In testing, the reactive performance of the motors exceeded expectations to a
point where even minute changes in control would be seen at the motor. The motors’ low inertial quality also allowed for faster than anticipated direction changes, ideal in an active heave compensated system where accuracy to follow the wave – fast – is vital. A by-product of the electrical motor operation is also electrical energy. The system becomes a generator in certain situations, e.g. when braking, and here the additional “regen” energy can be reused, stored or expelled as heat via resistor banks. The added environmental and operational benefits of electric motors are pushing a change in the industry too. “Each improvement in the power density and performance of electric motors means a wider range of suitable applications. Operators consider the lower operating expense of electric motors to offset their higher capital cost, compared to hydraulic motors,” Hatchett told InnovOil. “The NEWSBASE
industry also seems to be a seeing a decrease in the amount of hydraulic expertise it has available, which is also lending weight to electric motor selection. With the increase in reliability and the ease with which electric motor drive units can be changed out and reprogrammed (with less specialised experience), [this] has made electric drive systems far more maintainable.” Hydraulics are not going anywhere – they still provide a benefit for heavier applications and lower capital costs mean the economics are still persuasive for many operators. But for those that do, innovative applications such as these could prove to be valuable additions. In either case, SMD will be there to identify the best solutions for its customers. n Contact: Victoria Bossi
Tel: +44 (0)191 234 2222 Email: marketing@smd.co.uk Web: www.smd.co.uk
page 20
InnovOil
October 2017
COMMENTARY
L
OW oil prices are driving contracts altogether, while overcapacity in consolidation across the sector, the offshore segment takes several years yet including among the offshore drilling to clear”. companies. The number of rigs waiting for work, though, continues to be Crunching the numbers high and can only be solved through largePricing has been fairly resilient in the upper scale scrapping. Utilisation and day rates end of the rig market, with Transocean have declined, making it a perfect market reporting average rig rates of around for those looking to carry out opportunistic US$501,000 per day in the first half of 2017, drilling – although such flat on US$500,000 recorded demand is thin on the ground. in 2013. While rates have “Many of our There is, therefore, remained fairly static, though, rigs are on something of a perfect storm utilisation rates have plunged, contracts that from 92% in 2013 to 37% in for drillers. Low oil prices and low demand have cut off were negotiated 2017. Commenting on this, prospects for much offshore Transocean’s representative, a number of drilling. While the outlook for Pam Easton, noted that “many years ago” onshore work is slightly better, of our rigs are on contracts Pam Easton, largely in the US, pricing is still that were negotiated a number Transocean stubbornly low. of years ago”. The offshore will remain While the company’s challenged until prices go above US$60 per deepwater floaters appear to have held on to barrel, according to a recent report from activity levels – at around 67% in 2017 – this Moody’s rating agency. It went on to warn disguises the fact that it has slashed its fleet that revenues for offshore service companies numbers. In 2013, it had 14 of these floaters, would “continue to decline as customers but by early 2017 this figure had dropped to offer low-margin contracts, or avoid just three. Furthermore, prices have fallen
from US$353,300 per day to US$195,500. It seems that not even price cuts can sustain activity with inelastic demand. As a result, rig companies have cut rig numbers, making the utilisation rates something of a moving target. Transocean, four years ago, had a fleet of 82 rigs, excluding those under construction, whilst as of February this year it had 56 rigs. Some regions have fared better than others over the last four years. Africa has shrunk the furthest, from 36 rigs in 2013 to 12 currently. Angola has fared particularly badly, going from 11 in 2013 to two currently. Latin America has also fallen substantially, in a large part because of a slowdown in Brazil, which has slumped from 41 to 12, and Mexico, which fell from 35 to 15. The Middle East, meanwhile, is flat when considering 2013 and 2017, and even gained rigs in the intervening years, reaching 50 in 2015 and 2016. Abu Dhabi added rigs over this period, contributing to the 201516 peak, while China has also done an impressive job of holding on to rigs over the four-year stretch.
While oil prices are showing some signs of improving, the offshore rig market will continue to stall for at least another year, writes Ed Reed
Higher & NEWSBASE
October 2017
InnovOil
page 21
COMMENTARY
“New rigs with higher specifications tend to hold onto pricing better, they have a competitive advantage in tough markets. It’s sometimes better to have a job – even at a low price – rather than no job at all. Rigs capable of working in harsh environments have tended to do better in recent years,” Rystad Energy’s senior oilfield service analyst, Oddmund Føre, told NewsBase Intelligence (NBI). Economies of scale When the outlook is tougher, companies tend to band together, hoping to squeeze margins through cutting costs and relying on economies of scale. The two most notable transactions under way are Ensco’s purchase of Atwood Oceanics and Transocean’s purchase of Norway’s Songa Offshore. The Songa rigs are significant in that these are being upgraded, with Statoil, in pursuit of greater automation. The Transocean deal follows the company’s sale of its jackup fleet to Borr Drilling, for US$1.35 billion. Transocean is in the process of buying Songa Offshore, which has four rigs under contract with Statoil in Norway, for US$1.2 billion.
Overshadowing Transocean’s deals values for comparable asset opportunities”. is Ensco and Atwood. The move was Perhaps the most innovative of such plans announced in May, with Ensco making an was that from Rowan, in November 2016, all-stock merger offer, which would give about teaming up with Saudi Aramco on a Atwood shareholders a 31% stake in the new 50:50 joint venture. Rowan contributed three company. The deal values Atwood at around jackups to the venture, with plans for more US$860 million. as they come off contract in the country, The move has attracted a number while Aramco provided two of its own. of naysayers. One London-based asset Saudi is the top market for jackups in the manager, Arrowgrass world, Rowan explained, and the Capital Partners, in a public venture may order up to 20 more “New rigs letter described the deal rigs over the next 10 years. with higher as coming at a high cost, Consolidation among specifications with “inopportune timing companies can be seen as a sign and excessive risk”. It went tend to hold onto that buyers are confident of on to describe the move pricing better” improving prospects and intend as an act of charity on to position themselves to seize Oddmund Føre, the part of Ensco, “when these opportunities. Considering Senior oilfield service financial flexibility to sellers’ motivation does not cast withstand distressed industry analyst, Rystad Energy such a cheery light on the sector. conditions should be the primary strategic consideration”. Counter investments In response, Ensco has maintained that Where there is pressure, some see such a move will reaffirm its position and opportunities. Borr Drilling, which recently that it is paying US$222 per million per held an IPO in Norway, disclosed at the floater, covering four drillships and two end of August that it held a 9.7% stake in semi-submersibles, “significantly lower than Atwood Oceanics. The company increased
drier
NEWSBASE
page 22
InnovOil
October 2017
COMMENTARY
its stake in August, it revealed, after fellow driller Ensco announced a merger plan with Atwood. The Ensco offer values Atwood at a price of US$10.72 per share, while Borr, which holds its stake through forward contracts with a strike price of US$6.8-7.6 per share. The move has led some to suggest that Borr may be preparing to make a move on Atwood by itself, although this would require substantially more cash than the Norwegian company has to hand. A counter-offer from Borr is not necessary, though the company may just consider this to be an attractive investment opportunity. This process of cross-holding continues, with Schlumberger having a 20% stake in Borr – making it the single largest investor. Sidelined While companies wait for times to improve, rigs have been taken out of action and moored, waiting for an improvement in demand. Rigs can either be warm or coldstacked. The first keeps systems ticking over and a reduced crew on board. If a swift return to work is needed, this is the preferred option – although as a result of the higher state of readiness it is a relatively expensive option. Cold-stacking, meanwhile, involves
shutting down systems, virtually abandoning the facility. The cost savings of such a move are substantial. However, with greater savings come questions of to what extent a rig degrades. Many of the older rigs that have been coldstacked are unlikely ever to be brought back into service, but newer rigs may still offer attractive options. Part of the problem is that this equipment is not intended to be shut down. The question of how a company sees the future is essential in choosing whether to cold or warm-stack. A near-term recovery would suggest warm-stacking, while a more distant return would drive a cold stack decision. Bringing a rig back from being cold-stacked, though, will carry a substantial price tag. In this recent downturn, companies have talked of “smart-stacking”, supposedly a more sustainable way of coldstacking a rig. While this carries an upfront cost, it is cheaper – per day – than warmstacking. The true test of this technique will only become clear once demand for rigs picks up once more and companies attempt to restart idled equipment. Scrapping Given the pressure on drilling companies, rigs are being scrapped at a remarkable rate – and yet utilisation rates still remain fairly
The Galaxy II One of the rigs sold by Transocean to Borr Drilling in the May transaction was the Galaxy II jackup (left), which has been cold-stacked in Scotland, next to its siblings, Galaxy I and III. The rig, which has been renamed Brage by Borr, was built in 1998 and can operate in 122 metres of water. The Galaxy II was cold-stacked in September 2015 – not the first of Transocean’s rigs to be put on hold but also not the last. The harsh environment rig had been working for Engie in the UK North Sea, under a six-month contract at a US$192,000 day rate, down from US$214,000 under its previous contract. The Vanuaturegistered Galaxy II had previously been owned by Global Santa Fe, which struck a deal to merge with Transocean in 2007.
NEWSBASE
low. According to data from IHS Markit, 86 floaters and 33 jackups have been taken out of service during this downturn, with the expectation that this decommissioning will continue into 2019. Ensco, for instance, said earlier this year that it intended to retire a semi-submersible and six more jackups. Since 2014, it has sold 11 jackups, six semi-submersibles and two drillships. While the company has been working to reduce its fleet count, it has also added newer rigs – in addition to its deal to acquire Atwood. While new rigs continue to be built, from the backlog ordered during the highprice boom, the process is becoming more strained. Owners who have contracted new rigs often seek ways to avoid having to collect the finished product, leading to a number of legal disputes. It is not just rigs that are being taken out of the market. A number of companies are facing pressure to restructure, with Seadrill announcing a plan on September 12 to overhaul its finances. Bonds – worth US$2.3 billion – will be converted into around 15% of equity. Meanwhile, holders of the company’s common stock will receive around 2% of the new equity. Bankruptcies alone do not remove capacity. Seadrill has said it has sufficient resources to continue payments to supplies even while it operates under Chapter 11. This is comparable to the way in which a
InnovOil
October 2017
page 23
COMMENTARY Rigs in use 25
Utilisation rates adjusted for Transocean's diminishing fleet
20
15
10
5
0
2013
2014
Data source: Transocean
2015
2016
H1 2017
Ultra-deepwater floaters
Harsh environment floaters
Deepwater floaters
Midwater floaters
High-spec jackups
The harder they come
Data source: Baker Hughes 45 41
40 35
35
Rigs
30 25
20
2017 drilling deals
5
l Borr bought two jackups from Hercules Offshore for US$130 million.
3 0
l Transocean is buying Songa Offshore for US$1.2 billion. l Shelf Drilling bought three jackups from Seadrill for US$225 million.
Stacked
Cold-stacking: 2,000-10,000 Smart-stacking: 15,000
Source: Bassoe Offshore
NEWSBASE
2014 Brazil
2015 Mexico
2016
Australia
2017
Abu Dhabi
China
Day rates under pressure 600,000 500,000 400,000 300,000 200,000 100,000 0
Data source: Transocean's reports
2013
2014
2015
2016
Ultra-deepwater floaters
Harsh environment floaters
Midwater floaters
High-spec jackups
Data source: Baker Hughes
H1 2017
Deepwater floaters
Higher and drier
400 350
Cost per day US$
Warm-stacking: 40,000-60,000
2013 Angola
l Ensco is buying Atwood for US$860 million in stock. l Borr bought Transocean’s jackup fleet for US$1.35 billion.
12
11
10
US$ per day
Into the future Times are tough for drillers, but there are some signs that things are beginning to improve. Oil prices are beginning to show some signs of firming up, although this will be contingent on continued support from OPEC and the non-members who opted to cut production. Rystad is taking a cautiously optimistic stance on the sector’s prospects. “We expect a challenging year with slight growth into 2018 and a recovery towards the end of the decade and beyond,” Føre told NBI. Improved oil prices will “provide companies with stronger cash flows and therefore the ability to finance exploration. Prices have also come down, making projects more economically viable. Mature fields should offer attractive opportunities for infill drilling.” Signs of improving prospects for the market would come in an increase in tendering, the Rystad analyst said. Other positive signs picked out by Føre would be operators taking longer-term contracts, which would suggest a desire to lock in capacity at low prices. “A really good sign would be the reactivation of cold-stacked rigs; this would need contracts at premium prices, in order to cover the restart costs.” n
15
300
Offshore rigs
number of shale producers went through restructuring, allowing them to wipe out debts but continue pumping.
2017 data to date
250 200
150 100
50 0 Europe
2013 Middle East
2014 Africa
2015 Latin America
2016 Asia-Pacific
2017 North America
page 24
InnovOil
October 2017
WFR Tools: Fishing for Fishing and intervention specialist WFR Tools outlines the development of its one-trip SOLO subsea P&A tool, and why Offshore Well Intervention is the place to promote it
E
VER since there have been oil wells, pieces of equipment have been lost or stuck in them. Smarter equipment, automation and advances in controls may help to minimise failures, but the art of wellbore fishing is not going anywhere – and given the tough economics of today, it pays to have the right expertise and tools for the job. US-based Wellbore Fishing & Rental Tools (WFR) founded and built its business on providing those two things. Set up five years ago by seasoned fishing tool veterans, the Louisiana-based company provides drilling, completion, recompletion, casing exits, plug and abandonment (P&A), and thru-tubing solutions to oilfield operators in the Gulf of Mexico and onshore in the Permian Basin. Eschewing the approach of the traditional salesman, WFR’s technical sales personnel perform as consultants, advising on potential solutions and tools according to the particular intervention challenge at hand. In combination with a proactive stance on technology adoption and tool development, this has helped the business stand out. Speaking with InnovOil by phone, executive VP Johnny Hicks explained: “We’re a small focused company, and we’re very much involved with innovation and technology, that’s one of our differentiators – that and our experience.” The company’s five years in operation have seen it expand from a strong base of clients in subsea and deepwater developments in the Gulf to onshore work in the Permian Basin. New challenges meant new innovations were necessary, and resulted in the creation of new speciality tools and groups, across the company’s various service lines. Going SOLO “A lot of the technology today that we have focused on has involved deepwater
and specifically decommissioning and P&A. There is a big focus on that driven by necessity, and we’ve developed several systems,” Hicks continued. The first of these is the proprietary multi-string Marine Cutter intended for use in decommissioning or P&A operations. This is based on a two-bladed design to cut quickly through multiple strings of casing or large-diameter strings, and can be deployed from fixed or floating platforms, or on land. Its segmented design means the overall tool is more robust, reducing repair costs and downtime. WFR took the same modular approach in developing its section milling tool, using several components that are interchangeable with the multistring cutter, reducing inventory and footprint on the rig or platform. The reception from industry has been positive, and both tools now have hundreds of runs to date, Hicks added. From there the company looked at new applications, including section-in-a-section (SNS) tools. These are deployed when casings are cemented and the only way to plug off flow is to set a cement plug or a packer. “We built that tool as a system – it’s all new and it’s hydraulically actuated,” he said. “It can also be run in through a smaller casing and opened in a larger casing for section milling or cutting pipe.” “Looking to subsea and deepwater, we collaborated with TIW Corporation (A DrilQuip Company) as an exclusive Domestic USA service provider of their Downhole Casing Pull Tool. This collaboration identified a need for a mechanical set, releasable rotating spear,” he continued. This eliminates the need for a downhole motor and provides the option for multiple cuts in one run if required. The integrated “SOLO system” features multiple tools and is designed to enable an entire P&A operation – cut and retrieval – to be completed in a single run. Components include the Marine NEWSBASE
Bypass packoff sub
Cutter, a mechanical set rotating spear, combination ball drop-activated circulation and packoff sub. “The differentiator of the SOLO system is that it allows you to perform a subsea P&A in one run, avoiding a costly stripping job at surface and a non-sheerable event across the subsea BOP stack,” he added. The BHA is assembled with a hydraulic multistring cutter, the mechanical set and release rotating spear, and the ball-drop packoff sub spaced out in the string. Once the cut is complete, actuating the ball drop packoff sub allows the “B” annulus to be circulated clean of hydrocarbons and debris once the initial cutout is made. This spear can then be set and reset multiple times, allowing users to make a deep cut, release the spear, pull up and reset it below the subsea wellhead, then pull and lay down the casing string without incurring a major stripping job. “Response has been positive and encouraging but as with any new technology most don’t want to be first. However, after extensive testing several jobs are planned for the SOLO system in Q4 2017,” Hicks said. In addition to the in-house development of tools like SOLO, WFR also maintains close ties with other technology providers. “Since we are a new company with new
InnovOil
October 2017
ideas at OWI Mechanical rotating spear
fully certified and traceable inventory, we also have access to some of the newer technologies,” Hicks added. “We look for opportunities and work very closely with our [original equipment manufacturers] OEMs for new tools or any new technologies that they may have and how we could incorporate that into our inventory.” Attention to decom Awareness of the cutting edge is important, especially given the changing nature of this particular sub-sector. Older operations, particularly open-hole fishing, he said, are far less necessary today than perhaps 20 years ago. “There is less open-hole fishing in the drilling environments because operators are already directionally drilling – it is so much faster and easier to sidetrack a well, and the economics today do not support a long open-hole fishing job. When you compare the cost of recovering a BHA versus the cost of a day rate on a drillship or a semi-sub, it’s just much more efficient to go around it,” he added. That means the fishing tool providers like WFR are adapting their expertise to meet new demands. “What we see today is an ever-growing number of wells that need P&A and platforms that need to be
page 25
The “SOLO System” is composed of multiple tools, designed to work together to perform the P&A operation in a single run
WFR segmented cutter
decommissioned. That means opportunity for WFR and others in our service sector because a lot of our inventories are already designed and proven for decommissioning operations.” That also means looking to horizon technologies, such as riserless P&A techniques, which would allow tools to be deployed by intervention vessels rather than drilling rigs. “There are a lot of wells out there that operators would like to plug with riserless systems, and we’re looking into those applications now,” Hicks added. Knowledge box Hicks also cited the Offshore Well Intervention (OWI) conference as an ideal forum for surveying new technologies, and for WFR to showcase its own. The dedicated Gulf of Mexico event, taking place in Houston over November 1-2, will see a range of new well intervention case studies and technology innovations, such as new completion designs, workover technology and late life management solutions. Delegates include operators, service providers, sector experts and tool manufacturers. For Hicks and WFR, it has also provided a platform for networking as the company looks to expand its operations to include NEWSBASE
tool services in international markets such as Europe and West Africa. He will also be presenting on the development and benefits of the aforementioned SOLO system. “OWI is a good link to operators and to others in the sector that we are in – it’s a focused group which allows us to find a lot of common ground for learning and discussion,” he added. In the meantime, WFR will continue to push its emphasis on expertise and personnel just as much as new technology. “We’re proud of our products, we take things personally, and we realise that with budget constraints how they are today, every run counts,” Hicks told InnovOil. With the company’s knowledge, and with tools like SOLO at its disposal, one run might be all you need. n The 2017 OWI Gulf of Mexico event takes place in Houston, Texas, November 1-2. To enquire or to book your place, visit interventiongom.offsnetevents.com or contact Sam Scarpa on sscarpa@offsnet.com Contact: WFR Tools
Tel: (+1) 855 591 3474 Email: jhicks@wfrtools.com Web: www.wfrtools.com/
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Waste not … Baker Hughes is to develop a 100mmcf per day processing plant to reduce the flaring of gas in Iraq
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AGHDAD made progress in July on an intensifying drive to reduce the flagrant quantities of associated gas wastefully flared from the country’s giant southern oilfields. US engineering giant GE, a well-established government partner, has been enlisted on a project to monetise the resource in Dhi Qar Province. The deal was accompanied by a series of professions of intent to develop the sector further. The nascent Iraqi gas industry passed a symbolic milestone last year with the first exports, but the federal government was also forced last month to commence imports of the natural gas required for domestic purposes from neighbouring Iran. Meanwhile, a survey by the international body leading the drive to reduce flaring confirmed that the volumes being expensively wasted remained among the world’s highest. A flare for projects In July, the federal Ministry of Oil (MOO) signed a contract with Baker Hughes – a GE company since a merger with the former GE Oil & Gas division earlier this year – to carry out a two-phase project to recover hitherto flared gas from the Gharraf and Nasiriyah oilfields in the southern Dhi Qar province. The first, fast-track scheme covers the installation of a modular gas-processing plant located at Nasiriyah – some 200 km north-west of Basra – to produce around 100 mmcf (2.8 mcm) per day by
dehydrating and compressing associated gas from the two fields. The plant will subsequently be expanded into a complete natural gas liquids (NGL) plant – recovering around 200 mmcf (5.7 mcm) per day of dry gas, LPG and condensate. The dry gas will be used chiefly in domestic power generation, while the LPG and condensate will be deployed first to meet local demand for cooking fuel – with the remainder sent for export. GE is heavily involved in Iraq’s electricity sector, supplying equipment for around 60% of the country’s generation capacity. The firm was also involved well before the Baker Hughes merger in activities further upstream. In 2013, the US company established a base in the north of the supergiant Rumaila field – source of more than a third of federal production of 4 million bpd – to supply equipment and services to the companies involved in developing the asset. GE supplied five gas turbines for the 235MW North Rumaila power plant, due to be commissioned later this year and running on associated gas captured from the field. Stunted development The estimated 1.3 billion barrel Gharraf field, located around 85 km north of Nasiriyah City, is operated by Malaysia’s Petronas, which holds 45%. It is partnered by Japan Petroleum Exploration (JAPEX) with 30% and state-owned North Oil Co. (NOC). The licence was awarded during Baghdad’s second international licensing round in late 2009.
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Production belatedly commenced at 100,000 bpd in 2014 but the tendering process initiated the following year to more than double output in pursuit of a plateau target of 230,000 bpd appeared to stall in the wake of the government’s financial and security crises erupting that year. South Korea’s STX Heavy Industries won a US$99.5 million, two-year contract in January 2014 to install a 46 mmcf (1.3 mcm) per day gas treatment unit at the field, processing gas from the Mishrif oil train for supply to a nearby power plant. Current production at Nasiriyah – which remains operated by the government – is believed to stand at around 70,000 bpd. The primary immediate aim of the gas development efforts is to meet the domestic shortfall of sales gas – and the accompanying popular anger at the serious power and fuel shortages thereby created. Huge and growing volumes continued to be flared while the government was forced to commence long-awaited imports from Iran last month. Supplies from its neighbour started at 7 mcm per day and are due to rise to 35 mcm per day at an undetermined date in the future. However, the time taken for the first phase of the long-standing import agreement to be realised has created some doubt around the latter, as Iraq accelerates progress on developing indigenous resources. Gas rises The government fulfilled a decades-old goal of exporting gas last year by recording the first overseas shipments of condensate and LPG in March and July respectively. Oil Minister Jabbar al-Luaibi marked the opening of a third loading dock
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for liquid gas at Umm Qasr port in late July by declaring that gas production was on track to reach 1.3 bcf (37 mcm) per day by the end of the year, with condensate and LPG exports due to rise commensurately. A press release issued by the ministry shortly afterwards noted that condensate and LPG exports during the first six months of the year had totalled around 356,000 cubic metres (2.2 million barrels) and 59,370 tonnes respectively. Baghdad’s development of the gas sector has an advantage over that of the country’s lifeblood oil industry in garnering direct foreign donor support in view of the huge environmental benefits. Aware of the burgeoning financial losses of flaring and under pressure from potential international funders, the government signed up in 2011 to the World Bank-led Global Gas Flaring Reduction Partnership (GGFRP). The commitment was followed two years later by the creation of Basrah Gas Co. (BGC) to implement the estimated US$17.5 billion so-called South Gas Utilisation Project (SGUP), designed to develop the infrastructure for the treatment and distribution of associated gas from the giant Rumaila, West Qurna 1 and Zubair fields in Basra Province. The government conducted a gas-focused third international upstream bid round in late 2010 – apportioning the Siba field in the south, Akkas in the west and Mansouriya near Baghdad in the centre. Development of the latter two has been delayed by security problems, while Siba, operated by privately owned Kuwait Energy Co. (KEC), is due on stream producing 100 mmcf (2.8 mcm) per day by the end of next year. The fourth auction, conducted in 2012, included a number of gas fields but received a disappointing response attributed in
InnovOil
part to the country’s underdeveloped gas infrastructure – which the SGUP is designed to address. According to the GGFRP, the five largest oilfields in the oil-rich Basra province account for around 65% of the country’s current flaring. BGC is a joint venture comprising state-owned South Gas Co., Royal Dutch Shell and Japan’s Mitsubishi. Financial assistance for such efforts has been provided through a Development Policy Financing agreement with the World Bank, first signed in late 2015 and renewed in December – in each case entailing a concessionary loan of US$1.2 billion to support projects and policies geared towards energy efficiency among other goals. The GGFRP’s annual report, published on July 10, showed the quantity of gas flared by Iraq in 2016 rising against global trends by 1 bcm to just under 17 bcm – the second highest in the world after Russia and, unlike the latter, with a ratio to oil production well above the world average. In an announcement to celebrate Baghdad committing to the international body’s initiative to eliminate routine flaring entirely by 2030, the partnership’s sponsors enumerated the extent of the current wastage. Annual economic losses to Baghdad were estimated at US$2.5 billion, while the flared gas was said to be sufficient to meet the bulk of the country’s requirements for gas-based power generation and to support incremental capacity of around 8,500 MW. The ‘zero-flaring’ agreement also commits the government not to flare gas at new field developments – and the terms of an abortive licensing round launched late last year included a requirement to utilise associated gas from any development. n
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TUSSIA is already the world’s biggest producer and exporter of natural gas, and it hopes to triumph in the burgeoning LNG industry as well. This will take some work, as the country is currently home to just one large-scale gas liquefaction plant – Sakhalin LNG, which accounts for only 4% of global supplies. (By comparison, Qatar, the largest supplier, controls just under 30% of the market.) But production levels are on the way up. Novatek, Russia’s largest privately owned gas producer, is due to launch the first production train of its Yamal LNG plant before the end of this year. The facility will eventually be able to turn out 16.5 million tpy of LNG, and this is enough to raise Russia’s total gas exports by 10%, Russian Deputy Energy Minister Anton Inyutsyn said last month at the World Petroleum Congress (WPC). This development is encouraging, as it indicates that Russia is moving towards becoming a truly global gas supplier. But it also brings up questions about Moscow’s strategy for LNG exports.
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Pipelines vs. ports Before the launch of the Sakhalin LNG plant, the country’s state-run gas monopoly Gazprom was almost entirely dependent on pipelines for exports. This dependence limited its geographical reach, since by definition, pipelines can only pump gas to fixed or designated delivery sites. LNG, by contrast, can be loaded onto tankers and then shipped to any port in the world that has the requisite intake facilities. It is therefore a much more flexible option for Gazprom and other companies that hope to develop a truly global reach. In other words, Russian firms that can produce or supply LNG will be in a better position to tap foreign markets, as they will be able to operate over a wider geographic range. Moreover, they will not have to lobby Gazprom, which guards its monopoly jealously, for permission to use its export pipeline network. Yet market access is not the only consideration. LNG plants tend to carry
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higher price tags than pipelines that handle comparable volumes of gas, so they are less economical at times when gas prices – and crude oil prices, to which gas prices are often contractually linked – are relatively low, as they are now. They also require more infrastructure – marine tankers, port facilities and building sites in addition to pipelines, roads and electrical grids. Some Russian officials have attempted to codify this balance between market access and upfront expenditures. Inyutsyn, for example, said earlier this year that it all came down to logistics. “If you transport natural gas more than 3,000 km, then it is more profitable to send it as LNG,” he said in his WPC speech. “But if it is less than 3,000 km, it’s better to send it by pipelines.” Going the distance This is an interesting assertion, given that Russia’s LNG sector has not exactly been
Russia’s LNG export formula Proximity to target markets is not the only consideration driving Russian companies to consider LNG projects, writes Jennifer DeLay NEWSBASE
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following this strategy. To date, most of Sakhalin LNG’s production has gone to Japan and South Korea, and both of these markets are considerably less than 3,000 km away from the Sakhalin-2 offshore field, which supplies gas for the plant. Yamal LNG will be different – as will Arctic LNG-2, Novatek’s next planned gas liquefaction plant, and Pechora LNG, the long-shot joint venture led by Rosneft and Alltech. All of these facilities are designed to serve Asian markets, but they will have to load their output onto ice-breaking tankers that travel long routes eastward across the Arctic Sea before passing through the Bering Sea towards the Pacific Ocean. Transportation costs are a key consideration for such projects. Indeed, Novatek said last week that it might set up a transshipment base on the Kamchatka Peninsula so that it could move LNG from ice-breaking tankers to larger vessels that are
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more economical for long-haul shipments. As such, they are good candidates for the application of Inyutsyn’s formula, which aims to encourage the creation of economies of scale. Inconsistencies Yet there are other projects that disregard such logic. For example, Rosneft has indicated that it wants to build its own LNG plant to process gas from the Sakhalin-1 offshore fields rather than negotiate a deal for the use of Gazprom’s Sakhalin LNG facility. This plant would also be located less than 3,000 km away from the lucrative markets of Japan and South Korea. Meanwhile, Gazprom is also looking at shorter-haul LNG delivery options. In early June, the gas giant signed a heads of agreement (HoA) with Royal Dutch Shell on the Baltic LNG project. The document laid out terms for the formation of a joint venture for the scheme, which targets
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markets in Europe and elsewhere. If built, the plant will have a production capacity of 10 million tpy. It would send LNG to market from a site in northwest Russia, which is less than 3,000 km away from several countries in Europe that already receive Russian gas via pipeline. Apparently, then, Russian companies are not drawing up their business plans with Inyutsyn’s formula in mind; rather, they are investigating several options, including longhaul and short-haul export routes. This is hardly a negative development, as it shows that would-be LNG exporters are not basing their decisions on distance alone. Instead, they are trying to decide what combination of proximity to target markets and other criteria such as projected demand, transport options and potential investors’ wishes will be most profitable. It remains to be seen whether the Russian government will be as flexible when the companies in question submit requests for permission to begin construction, so project leaders should treat the Kremlin’s stance as yet another consideration in their investment decisions. n
Nakhodka, Russia - July 28, 2017: Tanker RN-Polaris (above) bunkering anchored LNG tanker Energy Progress (below). Picture: Vladimir Serebryanskiy
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RGU forges new Japanese innovation links
Aberdeen’s Robert Gordon University is to expand its collaboration with Japan’s Nippon Foundation to develop skills and technology
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BERDEEN’S Robert Gordon University (RGU) and the Nippon Foundation of Japan (NF) – a non-profit social innovation hub – have signed a letter of intent (LoI) which will see the two collaborate in areas of ocean innovation. The agreement was announced at RGU on September 5, and will see the NF and the university continue to develop their relationship, following the university’s inauguration of the first summer school for 15 Japanese students in 2016. The NF is an independent grantmaking organisation founded in 1962. Its ocean-focused wing, the Ocean Innovation Consortium (OIC), was launched in Japan in 2016 and includes university, industry and public agency partners with the aim of developing people for different aspects of offshore development. Foundation chairman Dr Yohei Sasakawa was with the delegation in attendance at the signing. Dr Sasakawa said: “I would like to especially look to RGU to take the lead role so that RGU and the Nippon Foundation, hand in hand, co-operate not only in educating students but also strengthening and deepening our partnership with industry.” Expanding education is this field is a key priority for the Japanese government. The offshore sector in Japan is expected to be worth 50 trillion yen (US$450 billion) by 2030, and the country aims to boost the number of offshore engineers to 10,000 by that time –a five-fold increase from the current figure of just over 2,000. The hope is that the relationship with RGU can help support the training of new, skilled personnel for this market. The signing of the LoI occurred during the final week of the 2017 Ocean Innovation Consortium summer school at RGU, which has seen 10 students studying different aspects of marine engineering and some practical experience at the DART drilling
Nippon Foundation students completing the RGU summer school
Signing of the letter of intent between the RGU and Nippon Foundation. Photo: RGU simulation suite at RGU. The group also spent five days at The Underwater Centre in Fort William, undertaking diving and subsea training. Diversification RGU director of business development Donella Beaton explained to InnovOil that as Japan looks to a build a more diverse marine sector involving aquaculture, renewables and frontier projects such as methane hydrate development, the NF had sought the expertise of a number of NEWSBASE
universities worldwide in launching a marine engineering training programme. RGU’s broad links to industry, and its technical resources, helped the university stand out during early discussions with the NF in 2015. This relationship has grown, and with two successful summer schools now complete, the intention is to deepen the co-operation between the two organisations. Future projects may include further skills development, as well as co-operation in new marine engineering technologies. n
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Shell completes Prelude mooring New video update shows the securing of the 16 mooring chains holding the 500m-long facility in place
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T is shaping up to be a big couple of weeks in Australia’s Browse Basin. Icthys’ Venturer floating production, storage and offloading (FPSO) facility arrived at its permanent mooring in midAugust (See: September issue of InnovOil). The arrival of the Venturer followed just weeks after the maiden voyage of Royal Dutch Shell’s rival Prelude floating LNG (FLNG) facility to its new home, around 475 km off the coast of Broome in Western Australia. In mid-September, the company confirmed that it had been successfully secured to its mooring, where it will remain for its 25-year operational assignment, around half of its total expected lifetime. Shell operates the project with a 67.5% stake, alongside Inpex (17.5%), Korea’s KOGAS(10%) and Taiwan’s CPC (5%). At 488m long and requiring around US$12.6 billion in investment, Prelude puts the “mega” back into “megaproject.” It is the largest offshore facility ever constructed, displacing 600,000 tonnes of water, and built to withstand the tropical cyclones – up to category five – and rough seas of the NW Shelf. Critical to this is the facility’s gigantic mooring system, about which Shell explained more in a recent video update. This video covers the securing of number eight of the sixteen mooring chains to the facility’s turret, also one of the largest ever built. 17 km of chains were fabricated by Spain’s Vicinay Cadenas, amounting to a total of around 25,000 links. These were then aligned on the seabed, with the commissioning team on board pulling in each to within an accuracy of one or two links, pre-determined prior to the operation. The mooring was overseen by TechnipFMC, which has been tasked with project management, EPC and commissioning on the project, using its Deep Orient vessel. Innovation has been critical to the success of the project. All told, according to Lloyd’s Register the project has already generated over 150 patents. On board, the processing of gas and condensate occurs in modules that occupy an area approximately one quarter of the size of a typical onshore LNG plant. Shell’s Dual Mixed Refrigerant (DMR) process – originally developed to enable liquefaction
10,178 tonnes of Prelude anchor chains at NMT yard, Bilbao at the Sakhalin LNG project, where temperatures can range between +/-25°C – is used to liquefy the gas. Among other innovations, the system also uses waste heat from the process as a heat source for the gas treatment unit, to improve efficiency. LNG and LPG produced at Prelude will then be offloaded in a side-by-side vessel arrangement, using specially designed cryogenic loading arms. Condensate will be offloaded from the rear of the facility using a floating hose. In total, the company expects production NEWSBASE
to reach a minimum of 5.3 million tpy of liquids, of which 3.6 million tonnes will be LNG, 1.3 million tonnes will be condensate and 0.4 million tonnes LPG. While mooring looks to be on schedule, and hook-up and commissioning are set to continue into 2018, the company has not yet provided an official start-up date. Its current statement is that it “expects to see cash flow from the project during 2018,” with outside estimations suggesting this may begin sometime between April and September next year. n
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BW signs Borr jack-up BW Offshore has signed a letter of intent (LoI) with Norway’s Borr Drilling for two wells offshore Gabon, on the Dussafu project. The drilling company announced the LoI on September 12, saying its high-specification jackup Norve would carry out drilling and completion work on two subsea development wells. This work should take 140-160 days, it said, and will start in January 2018. The dayrate was not disclosed for the work. Borr’s CEO, Simon Johnson, welcomed the agreement with BW Energy Dussafu, the subsidiary working on the Gabonese project. “This fixture demonstrates our customer’s confidence in Borr’s premium assets and highly
capable organisation. We look forward to finalising this contract and working with BW to deliver excellent operational performance and high-quality wells.” Borr bought the Norve rig in May 2017 when it acquired Transocean’s 15 jackups, in a deal worth US$1.35 billion. The Norve was previously known as the Transocean Honor. Its previous owner stacked the jackup in May 2016. The rig can work in water depths of up to 122 metres and was built in 2012. It is currently in Limbe, in Cameroon, and should be mobilised in December of this year. Before being stacked, the Transocean Honor had been working for Chevron in Angola on a one-year contract, at a US$194,000 dayrate. BW Energy Gabon acquired stakes in Dussafu from Harvest Natural Resources and Panoro Energy in April, giving it a majority holding in the field. The company, which specialises in floating
production systems, said in August that it intended to use the Azurite floating production, storage and offloading (FPSO) unit on the field. This unit has been moved to the Keppel yard to undergo upgrades. The unit had been used by Murphy Oil on a field in Congo Brazzaville and was notable for also having drilling capacity. The Congolese field was a disappointment and the company released the FPSO back to BW early, in early 2014. n Edited by Ed Reed edreed@newsbase.com
Baker Hughes wins Zohr phase two work Baker Hughes has won a subsea contract for the second phase of work on Egypt’s Zohr gas field. Announcing the award on September 9, GE-owned Baker Hughes said it had won work from Petrobel, a joint venture of Eni’s IEOC and Egyptian General Petroleum Corp. (EGPC). The value of the deal was not disclosed. The service company will provide project management, engineering procurement, fabrication, construction, testing and the transportation of a subsea production system. This will include “seven manifolds, tie-in systems, long offset subsea and topside control systems, SemStar5 HIPPS (high integrity pressure protection systems), workover systems and tools, and will support the installation, commissioning and start-up operations,” it said. The signing ceremony involved Egyptian Minister of Petroleum and Mineral Resources Tarek El-Molla. Also in attendance were Petrobel’s CEO, Atef Hassan, Baker Hughes’ Rami Qasem and two other Egyptian officials. The minister noted the importance of securing the utmost returns from domestic energy resources. “We are able to increase the value and efficiency of the sector by driving a sustainable and energy-efficient economy through the ministry’s Modernisation Programme in partnership with companies such as [Baker Hughes]. The Zohr gas field is playing a major role in the development of Egypt’s domestic energy resources, revenue generation and economic growth.” Baker Hughes’ president and CEO, Lorenzo Simonelli, described Zohr as “one of the most significant developments of its kind, and through this project we can show the efficiency gains that such complex projects can achieve through our enhanced portfolio”. He went on
Borr’s Norve rig when it was still branded as the Transocean Honor
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to note that supplies of gas from the field would save the country billions of dollars through avoiding imports. The company is also supplying wellheads to the project, under a separate award from earlier this year. The first phase of Zohr is due to begin producing by the end of this year. Baker Hughes also recently won work from Eni on the Coral South LNG project, in Mozambique. n Baker Hughs
Schlumberger Announces DELFI Cognitive E&P Environment Schlumberger has unveiled the new DELFI cognitive E&P environment at the SIS Global Forum. This environment enables collaboration across exploration and production (E&P) teams and leverages the full potential of all available
data and science to optimize E&P assets. The DELFI environment leverages digital technologies including security, analytics and machine learning, high performance computing (HPC) and Internet of Things (IoT) to improve operational efficiency and deliver optimized production at the lowest cost per barrel. The DELFI environment will provide a new way of working for asset teams by strengthening integration between geophysics, geology, reservoir engineering, drilling and production domains. The openness and extensibility of the DELFI environment will enable Schlumberger customers and software partners to add their own intellectual property and workflows in the environment. “DELFI enables our customers to take advantage of E&P domain science and knowledge using the latest digital technologies to unlock the value in all data for making critical business decisions,” said Ashok Belani, executive vice president, Technology, Schlumberger. “With the launch of the DELFI environment, we deployed an E&P Data Lake on the Google Cloud Platform comprising more than 1,000 3D seismic surveys, 5 million wells, 1 million well logs and 400 million production records from around the world, demonstrating a step change in scalability and performance.” As an example, in the Gulf of Mexico, Schlumberger processed high-resolution wide and full azimuth seismic data over a 100,000 km2 area in the DELFI environment. Scalable HPC on Google Cloud Platform enabled high-resolution depth imaging using reverse time migration and full waveform inversion technologies, resulting in a significant reduction in project turnaround time. n SCHLUMBERGER
DELFI Cognitive E&P Environment
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Eni books Saipem rig for Morocco work Chariot Oil & Gas, following its recent relinquishment of two blocks in Namibia, has set out plans for the drilling of the RD-1 well, in Morocco’s Rabat Deep licence. The well is targeting the JP-1 prospect. The company, in a statement on September 7, said the operator, Eni, had signed up the Saipem 12000 drillship to carry out the work. The rig is a sixth generation ultra-deepwater drillship. It will be working in Morocco on a one-well slot. Eni has a 40% stake in the block, while Woodside Petroleum has 25%, Office National des Hydrocarbures et des Mines (ONHYM) has 25% and Chariot has 10%. The minnow also confirmed that drilling of the well had slipped to the latter part of the first quarter of 2018. The company had previously expressed the hope that this might come in the fourth quarter of 2017 but recent statements, from Woodside among others, made it clear the well would be delayed to next year. “We are pleased to see Eni progress operations on the Rabat Deep Offshore acreage and secure the high-performance Saipem 12000 drillship to drill the JP-1 prospect, one of Chariot’s priority targets,” said Chariot’s CEO, Larry Bottomley. Eni signed on to work with Chariot on this Moroccan licence in January of this year. The executive went on to say success at the well would provide “transformational value … [owing] to the large scale prospective resources,
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excellent commercial contract terms and robust economics. Success will also materially de-risk other targets we have identified within our neighbouring Mohammedia and Kenitra permits in which Chariot holds a 75% interest.” The prospect is a four-way dip-closed structure covering around 200 square km, with a gross mean prospective resource of 768 million barrels. The Saipem rig carried out work for Eni off Portugal in 2016. Eni and Saipem often work together, with the former holding a substantial stake in the latter. In addition to discovering the Zohr field together, in Egypt, Saipem also recently announced construction work for Eni in Angola and Ghana. n Edited by Ed Reed edreed@newsbase.com
Mitsui OSK buys into India’s Swan LNG project JAPANESE shipping company Mitsui OSK is to soon purchase an 11% stake in Swan LNG, a subsidiary of India’s Swan Energy that is in the process of organising the installation of a 5 million tpy floating storage and regasification unit (FSRU) at Jafrabad in India’s Gujarat State on the west coast. This will be India’s first newbuilding floating LNG (FLNG) project as the country moves to diversify its energy sources Mitsui OSK has agreed to pay US$13 million for an 11% interest in Swan LNG, which will manage the terminal and the port facilities for the project, which is due to come into operation in 2020. The purchase will leave Swan Energy with a 63% stake in Swan LNG while two state-owned companies in Gujarat will hold a combined interest of 26%. The Japanese company has announced this week that it also intends to buy 26% in Triumph Offshore, another Swan Energy subsidiary that will own the FSRU, which South Korea’s Hyundai Heavy Industries (HHI) is currently constructing, for US$260 million. Mitsui OSK is reported as planning to complete the purchase by the end of 2019. Mitsui OSK will supply the floating storage unit (FSU) that will lie next to the FSRU. A second FSRU might be added to the project two years after the commissioning of the first if Swan determines that greater demand for LNG exists. The project will consist of a 180,000 cubic metre capacity FSRU and a 135,000-145,000 cubic metre FSU, plus a mooring jetty,
breakwater and onshore facilities. HHI is due to deliver the FSRU in late 2019 and cargoes will arrive during the first quarter of 2020. Mitsui OSK announced earlier this month that it had signed agreements with Swan LNG regarding the long-term operations and maintenance of an FSRU and the provision and long-term operation and maintenance of an FSU. Four companies have already agreed to lease the full capacity of the FSRU: Indian Oil, Bharat Petroleum Corporation Ltd (BPCL), Gujarat State Petroleum Corp. (GSPC) and Oil and Natural Gas Corp. (ONGC). n Edited by Andrew Kemp andrew.kemp@newsbase.com
Swedegas contracts MAN Cryo to build LNG bunker station SWEDISH infrastructure company Swedegas has contracted MAN Cryo, a division of MAN Diesel & Turbo, to build the first LNG bunkering facility in the Port of Gothenburg. The facility will enable ships to bunker LNG Älvsborg suspension bridge over Göta älv in Gothenburg
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from trucks or containers while simultaneously loading and unloading at two jetties in Gothenburg’s energy port. This will eliminate separate refuelling stops, increase flexibility for customers and LNG suppliers, and the facility will be open to multiple suppliers, MAN Cryo said. The facility will consist of bunkering equipment, a discharge station for LNG trailers or containers, feeding pumps, and vacuum-insulated piping, the company said. “Our strategy to offer LNG solutions to the marine market, both on board vessels as fuel gas supply systems but also as bunkering infrastructure, dovetails perfectly with the general development towards cleaner ship propulsion,” Mikael Adler, managing director of MAN Diesel & Turbo, Sweden, said in a statement. The facility is due to come into operating in 2018. Swedegas will operate and manage the bunkering facility in co-operation with the Port of Gothenburg, which is the largest port in Scandinavia and handles 40 million tpy of cargo, about one-third of Sweden’s foreign trade. MAN Cryo is also located in Gothenburg and manufactures cryogenic equipment for LNG storage, distribution and handling. It will oversee the project under an engineering, procurement and construction (EPC) contract. Gothenburg now joins several ports that
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are installing LNG bunkering facilities with the intention of providing a more environmentally friendly fuel amid new European Union regulations on sulphur emissions. n Edited by Richard Lockhart richardl@newsbase.com
Altus and Qinterra form new well service company Qinterra Group’s North Sea well intervention specialist Altus Intervention and its international technology arm, Qinterra Technologies have united to form one global force in well services. With headquarters in Stavanger, Norway, the combined group will be known as ‘Altus Intervention’, bringing together over 1,000 staff across four global regions: UK and West Africa, Norway and Denmark, the Americas and Middle East, and Asia Pacific. Following EQT’s acquisition in 2014, the two companies Altus Intervention and Qinterra Technologies were created. The united business will now operate as one brand to offer an
enhanced range of innovative and field-proven well intervention technologies, tools and services to the global oil and gas industry. Group chief executive, Åge Landro, who joined in February 2016, will continue to lead the company as it pursues a strategy to make intervention smarter. He said: “This is a milestone in the evolution of Altus Intervention. With a strong heritage, unrivalled expertise and cutting edge technology, we are well placed to support oil companies as we shape the future of well intervention. The energy landscape is constantly evolving and we are focused on bringing forward smarter ways of working to increase efficiencies and drive down costs. “Combining our capacity and experience in well intervention will allow us to take bold steps towards adding to and developing our products and capabilities to support the oil and gas industry, worldwide.” n ALTUS INTERVENTION
BP clinches longawaited contract extension at ACG After years of drawn out talks, Azerbaijan and a BP-led consortium have agreed to extend the production-sharing contract (PSC) for the ex-Soviet republic’s largest oil asset up to 2050. NEWSBASE
The Azeri-Chirag Deepwater-Gunashli (ACG) fields form the bedrock of Azerbaijan’s oil-driven economy, accounting for 80% of national crude production. Last week’s landmark agreement is expected to unlock over US$40 billion in investments over the next 32 years, helping to slow down the rate of output decline at the ageing deposits. Under the revised PSC, the project’s foreign investors will pay a one-off US$3.6 billion signing bonus to the Azeri government. Azeri state oil company SOCAR will raise its stake in the project from 11.65% to 25%, while BP’s share will drop from 35.8% to 30.37%. The British major will remain operator of the fields, however. Meanwhile, Chevron’s holding will shrink from 11.3% to 9.57%, while Japan’s Inpex will lower its stake from 11% to 9.31%, Norway’s Statoil will cut its share from 8.6% to 7.27%, ExxonMobil from 8% to 6.79%, Turkish Petroleum from 6.8% to 5.73%, Japan’s Itochu from 4.3% to 3.65% and India’s ONGC Videsh Ltd (OVL) from 2.7% to 2.31%. BP and its partners signed the original PSC for the ACG fields in 1994, dubbed “the contract of the century” for its transformative impact on Azerbaijan’s economy. This agreement had been due to expire in 2024. “Finalising the contract extension is fitting recognition of the value that ACG represents – not only for BP and its partners but also the Azeri economy,” Wood Mackenzie analyst Laura Bennie said in a statement. “The combination of the extension, bonus payment and increased SOCAR stake looks like a balanced outcome.”
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InnovOil
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NEWS IN BRIEF
Situated around 120 km off the coast of Baku, the ACG fields have already yielded over 3 billion barrels of oil since commercial operations began in 1997. Wood Mackenzie estimates that a further 3 billion barrels will be extracted between now and 2050. Output at the deposits has been flagging ever since it peaked at over 820,000 bpd in 2010, averaging just 585,000 bpd of crude in the first half of 2017. BP is expected to launch a seventh platform at the site – Azeri Central East – in the 2020s, helping to slow down the rate of production decline. The project is pending a final investment decision (FID). “The long-term trend will be decline, but there will be sustained high investment to make the decline as slow as possible,” Ashley Sherman, a senior analyst at Wood MacKenzie, told NewsBase Intelligence (NBI). He added that future output would depend largely on drilling levels and reservoir performance. n
Flares at South Pars, Iran
Edited by Joe Murphy josephm@newsbase.com
Ashtead Technology signs five-year agreement with TSC Global subsea equipment specialist, Ashtead Technology has signed a five-year global collaboration agreement with Technical Software Consultants Limited (TSC), part of Eddyfi Technologies, for its Alternating Current Field Measurement (ACFM®) instruments. The agreement will see Ashtead Technology combine TSC’s ACFM® equipment rental fleet with its own rental fleet and will manage all rental activity worldwide for the Amigo™ and U31™ subsea systems, as well as the latest PACE® instrument. Acquired by Eddyfi Technologies in May 2017, TSC has significantly contributed in shaping the landscape of electromagnetic testing technologies over the last 30 years. The ACFM® technology is specified by owners and operators of safety-critical infrastructures worldwide and is accepted as one of the most reliable methods of detecting and sizing surface-breaking cracks in metallic components and welds. ACFM® equipment can be utilised topside and underwater, up to depths of 2,000m and can be deployed remotely. n ASHSTEAD TECHNOLOGY
Sofregaz to cut Iran’s South Pars flaring NATIONAL Iranian Oil Co. (NIOC) has contracted France’s Sofregaz and Iran’s Sanat Sazeh Samin to reduce gas flaring at the offshore South Pars fields in the Persian Gulf. The gas will then be diverted to enhancing recovery from the many phases of the field’s gas development and from its oil layer. The 42 million euro (US$50 million) investment is the first in Iran’s South Pars Sustainable Development Project, which is designed to cut flaring and halt environmental damage brought on by the practice as Iran works to bring the giant gas field into full utilisation. NIOC has plans to develop the gas field through 24-30 phases and ultimately produce up to 850 mcm per day of gas. Sofregaz is to apply the appropriate technology supplied by Technip for the recovery of gas at a refinery serving Phases 2 and 3 of South Pars, with recovery anticipated NEWSBASE
to be 500,000 cubic metres per day. Iran plans to invest US$500 million in projects to bring gas flaring from the South Pars under control and put the gas to better use, Iranian media reported last week. Managing director of the Pars Oil and Gas Co. (POGC) Muhammad Meshkin-Fam told Iran’s Press TV that reducing the level of industrial pollutants was an important issue for the country. He said that he hoped the Sofregaz contract would be the starting point for similar contracts for all 13 gas processing plants planned for South Pars development and that eventually no gas should be flared. POGC has invested US$70 billion in South Pars and intends to invest a further US$20 billion, from which the US$500 million for gas recovery would come, he said. Meshkin-Fam told Iranian media that international sanctions had prevented Iran from pursuing further efforts to reduce gas flaring. Iran ranks among the 10 countries responsible for 75% of flared gas in the world, and that it is the top flaring country in the Middle East. “We hope this situation would change,” he said. The project’s construction will take 24
October 2017
InnovOil
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NEWS IN BRIEF
months and another commissioning will require another six months. n
“This move is of great significance as it marks that China ushers a new stage in gas hydrate exploration,” Xinhua said. “It will further accelerate China’s industrialisation of gas hydrate.” Drilling will re-start in the Shenhu area of the sea, about 300 km southeast of the Guangdong coast. It was in this area that Chinese drillers acting for CNPC tapped methane hydrates over several weeks in May and early June, state media reported. At the time, China Daily quoted Guangzhou Marine Geological Bureau as claiming that gas separation had reached 6,800 cubic metres per day for a time. The new agreement involves CNPC’s listed arm, PetroChina, whose vice chairman and president Wang Dongjin separately told a midyear results conference on August 24 that the company anticipated marketing commercial gas in Guangdong from undersea methane hydrates by 2030. Wang also said the NOC intended to accelerate exploration of methane hydrates in the Bohai Rim, the region on the Bohai Sea in China’s far northeast bordered by major cities such as Tianjin and the capital Beijing. The new campaign in the South China Sea will include drilling one or two new wells with the Chinese-made deepwater semi-submersible rig Bluewhale 1, which was also used for the methane hydrate test in May. However, CNPC chairman Wang Yilin has cautioned that the drillers will face tough technical challenges as well as the need to be careful in the face of potential environmental hazards such as the escape of methane. n
China advances in methane hydrate race
ABB to acquire GE Industrial Solutions
CHINA has taken another step forward in its ambitions to commercially tap its reserves of methane hydrates. National oil company (NOC) China National Petroleum Corp. (CNPC) last week signed a “strategic co-operation” agreement with the Chinese Ministry of Land and Resources (MLR) and the government of Guangdong Province. Under this, exploratory drilling for methane hydrates will resume and expand in the South China Sea, state news agency Xinhua reported. Media reports said the new drilling would begin in 2018.
ABB today announced the acquisition of GE Industrial Solutions, GE’s global electrification solutions business. In 2016, GE Industrial Solutions had revenues of approximately US$2.7 billion, with an operational EBITDA margin
Edited by Ian Simm ians@newsbase.com
Edited by Anna Kachkova annak@newsbase.com
NEWSBASE
of approximately 8 percent and an operational EBITA margin of approximately 6 percent. ABB will acquire GE Industrial Solutions for $2.6 billion; the transaction will be operationally accretive in year one. ABB expects to realize approximately $200 million of annual cost synergies in year five, which will be key in bringing GE Industrial Solutions to peer performance. As part of the transaction and overall value creation, ABB and GE have agreed to establish a long-term, strategic supply relationship for GE Industrial Solutions products and ABB products that GE sources today. “With GE Industrial Solutions, we strengthen our Number 2 position in electrification globally and expand our access to the attractive North American market,” said ABB CEO Ulrich Spiesshofer. “Combined with the long-term strategic supply relationship with GE, this transaction creates significant value for our shareholders.” He added: “Together with the GE Industrial Solutions team, we will execute our wellestablished plans in a disciplined way to bring this business as part of the global ABB family back to peer performance. With this next step of active portfolio management, we continue to shift ABB’s center of gravity, in line with our Next Level strategy, by strengthening competitiveness, mainly in the North American market, and lowering risk with an early-cycle business.” GE Industrial Solutions will be integrated into ABB’s Electrification Products (EP) division, resulting in a unique global portfolio and very comprehensive offering for North American and global customers. They will benefit from ABB’s innovative technologies and the ABB AbilityTM digital offering coupled with GE Industrial Solutions’ complementary solutions and market access. Included in the acquisition is a long-term right to use the GE brand. ABB will retain the GE Industrial Solutions management team and build upon its experienced sales force. After closing, this transaction will have an initial dampening effect to EP’s operational EBITA margin. ABB commits to returning EP to its target margin corridor of 15-19 percent during 2020. n ABB
23 November 2017 The Waldorf Hitlon, London
The Future of North Sea Oil & Gas Efficiency, exploration and innovation – keys to the success of the UKCS
The Future of North Sea Oil & Gas gathers senior level executives to discuss the overarching issues which face operators working in the continually maturing UKCS. The event looks at strategy and innovation taking place at the top level to improve productivity and profitability.
The 2017 edition of the conference will play host to our strongest ever line up of speakers during a period of renewed optimism. With the oil price having stabilised after a period of intense decline, E&P companies are growing more and more confident that there is still significant value remaining.
Here are just some of the event’s expert speakers:
Tony Durrant Chief Executive Officer Premier Oil
Hedda Felin Senior Vice President, UK & Ireland, Offshore Statoil
Dr Robert Trice Chief Executive Officer Hurricane Energy
UK Managing Director & Senior, Vice President, Europe
Morten Kelstrup UK Managing Director Maersk Oil
Algy Cluff Executive Chairman and Chief,Executive Officer Cluff Natural Resources
Graham Stewart Chief Executive Officer Faroe Petroleum
John Martin Chied Executive Officer Hansa Hydrocarbons
Ray Riddoch
Nexen
Please visit www.marketforce.eu.com/northsea1 to find out more about this exciting event, and use discount code EUROIL17 for a 10% discount!
October 2017
InnovOil
What next …?
To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections
If EC-OG’s Subsea Power Hub could help bring more cost-effective power to your subsea installation, contact Graceann Robertson on +44 (0)1224 933 301 or email info@ec-og.com For more information on ABB’s 100-MW subsea electrification project, or any other subsea power equipment, please contact Rita-Wei Fu via rita-wei.fu@no.abb.com or visit www.abb.com/oilandgas The 2017 OWI Gulf of Mexico event will take place in Houston, Texas, November 1-2. To enquire or to book your place, visit interventiongom.offsnetevents.com or contact Sam Scarpa on sscarpa@offsnet.com WFR Tools will also be attending the OWI event, and showcasing its one-trip subsea P&A SOLO tool. For more information, contact Johnny Hicks on (+1) 855 591 3474, or email jhicks@wfrtools.com To make an enquiry about SMD’s electric winches, or any other subsea equipment, contact Victoria Bossi on +44 (0) 191 234 2222, tor email marketing@smd.co.uk To learn more about Lloyds Register’s 3D printing certification, please visit www.lr.org/additive-manufacturing
NEWSBASE
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from Zetechtics
January 2014 Issue 18
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Clariant Oil Services’ SURFTREAT® flowback aids
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