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Bringing you the latest innovations in exploration, production and refining Issue 42
QUESTIONING INTEGRITY A look at asset integrity solutions Pages 13-21
AU-VIPs
New research on AUV missions Page 6
BLITZKRIEG ON BOPS GE and Diamond make an new partnership Page 24
April 2016
InnovOil
April 2016
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Inside
A note from the Editor
5
The edge of reason
6
No time like a crisis
8
AUVs make autonomous decisions
The Industry Technology Facilitator annual Technology Showcase in Aberdeen
Contacts:
On the radar
Media Director Ryan Stevenson ryans@newsbase.com
What caught our attention outside the world of oil and gas this month
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ASSET INTEGRITY 13
Media Sales Manager Charles Villiers Email: charlesv@newsbase.com
Integral to integrity
14
Editor Andrew Dykes andrewd@newsbase.com
Lockheed Martin report
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Innovative coatings from Hempel help fight corrosion
Technologies and techniques which could aid future asset integrity operations
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Watching assets like HAWX 19 Xodus Group’s online tool to simplify the process of asset integrity management
ROV star from Deep Trekker 20
Phone: +44 (0)131 478 7000
Compact, portable ROVs from Deep Trekker aid low-cost inspections
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Chevron fires up Gorgon 22
Design: Michael Gill michael@michaelgill.co.uk www.michaelgill.eu
Chevron has shipped its first cargo from the LNG megaproject in Western Australia
The Diamond and GE deal 24 How a new model for BOP services could be applied to other areas of the industry
Statoil to take Snorre subsea 27
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ction and refining tions in exploration, produ April 2015 Bringing you the latest innova Issue 42
A new axe to grind
28
The cut of one’s JIP
29
The LOTOS position
30
News in brief
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AxeBlade promises faster ROP
QUESTIONING INTEGRITY A look at asset integrity solutions
Boosting efficiency and lower the cost of subsea processing
Page X
Grupa LOTOS’ EFRA refinery upgrade AUV-IPS
New research on AUV missions Page X
BLITZKRIEG ON BOPS
Contacts 39
GE and Diamond make an new partnership Page X
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A note from the Editor The UK Oil and Gas Authority’s director of E&P Gunther Newcombe noted in March that: “Asset integrity is at the heart of the oil and gas industry.” While he is certainly correct, for all of the integrity-centric talk in the industry, many conversations around the subject in oil and gas remain behind the times. A new report from Lockheed Martin UK highlights the extent of some of this unexplored potential. In looking at new and developing technologies from other industries, its recent landscape report for the Oil and Gas Innovation Centre (OGIC) included everything from NASA-backed technology to training dogs to sniff out corrosion. You can read more about its findings inside this month’s issue. Similarly, coatings supplier Hempel explains the innovative chemistry and engineering behind its range of corrosion-resistant products, and how they can help protect asset integrity. It’s also interesting to note how times have changed in the corporate world. Doing some background reading on one of our features this month – an interesting new arrangement between GE Oil & Gas and Diamond Offshore, which will see the operator pay GE only while its blowout preventers (BOPs) are working – I came across an article from around five years ago. In it, a perfect storm of rig shortages, post-Macondo safety spending and a push to bring wells online faster has resulted in billions of dollars in backlogs and an industry that could not manufacture equipment fast enough. At the time of the article, drillers had begun to double-up on US$45 million BOPs in order to work longer and reduce potential downtime. In 2012, it was
predicted that as many as half of all new builds would be fitted with two BOPs. Now it seems that operators are struggling to justify paying for the equipment itself. But as in the case of GE and Diamond Drilling, innovative thinking can offer a new perspective. That was certainly one of the major themes put forward at the Industry Technology Facilitator’s Technology Showcase in early March. One of the best technology-focused events in Europe (nay the world?), its greatest success lies in putting technology providers and operators together in the same room, giving equal balance to the workshop and the boardroom. This year also saw ITF director Paddy O’Brien urge the industry to increase the speed at which it adopts new innovation. There remain no easy solutions around how to achieve this, the task should be helped – in the UK at least – by the creation of the Oil and gas Technology Centre (OGTC) in Aberdeen. You can read more about the project and the event inside. As well as innovative events, this month sees us discuss AUVs making increasingly autonomous decisions, a high-tech refinery upgrading project, a roundup of subsea JIPs and a nifty micro-ROV from Deep Trekker. Heeding the words of groups like ITF, this month’s InnovOil also includes our newest regular feature, which aims to keep you upto-date with some of the more intriguing and impressive innovations from outside the world of oil and gas. Stay tuned for more. All our features are also available through our brand-new website. For now however, the team and I are pleased to present the April edition of InnovOil.
Andrew Dykes Editor
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InnovOil
AUVs – at the edge of reason
April 2016
Researchers from the University of Delaware successfully programmed an AUV to make autonomous decisions during a marine mission
A
UTONOMOUS underwater vehicles (AUVs) just became a little more autonomous. A new paper from staff at the University of Delaware’s College of Earth, Ocean and Environment details some exciting improvements in the linking and processing of sensor data, allowing AUVs to adapt their missions according to what they detect. Mark Moline, director of the university’s School of Marine Science and Policy (as well as co-founder of its Robotic Discovery Laboratory), and Kelly Benoit-Bird of Oregon State University authored the report, published in the Robotics journal. The team formed the initial idea while conducting marine life studies in the Tongue of the Ocean, a deep sea trench in the Bahamas. Their experiment was designed to test whether a modular AUV could be programmed to make decisions autonomously and trigger new missions based on biological information – in their case, the size or concentration of squid – in its environment. When the sensors detected the correct size and concentration of squid, it triggered a second mission: to report the robot’s
position in the water and then run a preprogrammed grid to map the area in finer detail. Their report explains: “While there are numerous autonomous underwater vehicle (AUV) studies demonstrating data feedbacks to inform biological sampling, this study is uncommon in that a processed data product is used to identify a specific target in real time and improve sampling density of that target by a simple autonomous response.” Binary choices The writers outfitted a Kongsberg Maritime REMUS600 system with two Simrad EK-60 general purpose transducers/transceivers, one 38 kHz and one 120 kHz (frequencies routinely used in echosounders onboard vessels.) Because of the different ways in which these signals are reflected by marine life (either fish, mammals, or in this case, squid) the return signals can be processed and analysed to indicate what organism is being displayed, and its size. The AUV’s onboard computers can then use these processed signals to make decisions about what it is scanning – based on measurements of the squid’s size and density – and decide what it should do next. “After the three data products are
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generated, we determine a threshold for providing a positive signal,” the report notes. “If the criteria set in the data flow for size and number (here 100 squid > 20 cm long) is met, the custom application running on the stack sends a “1” to the vehicle’s RECON (Remote Control) computer, otherwise it sends a zero.” When a series of “1” signals are detected, the system takes control from the primary navigation computer and pauses its main mission, instead initiating a secondary mission. This sub-mission is undertaken either for a set period, until the mission is completed, or additional sensor data have met another set of programmed conditions. In a mission described in the paper, this was an expanding box grid “beginning with 100m separation between boxes, growing to 200m, and finally one at 500m separation.” After initial missions offshore California the system was also deployed in the Tongue of the Ocean during July 2015 did. Results were largely positive, with the REMUS successfully detecting squid and initiating its secondary mission to investigate the area further. This, the team said, “showed a number of spatial features in the
InnovOil
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The UDEL team explains how the AUV processes squid density. Source: Moline/Benoit-Bird
organism distributions that would have otherwise not been possible by other means,” such as scanning performed from surface vessels. However, results also suggested that the technology used had some directional limitations: because the REMUS lacks inertial navigation and relies on compass bearings, currents pushed the vehicle slightly off course, resulting in an asymmetrical mission area. That said, correcting such an issue would seem to be straightforward if inertial navigation is factored in. Mission accomplished In a statement, Moline explained: “It was a really simple test that demonstrated that it’s possible to use acoustics to find a species, to have an AUV target specific sizes of that species, and to follow the species, all without having to retrieve and reprogramme the vehicle to hunt for something that will probably be long gone by the time you are ready.” In a broader context, the paper “demonstrates the powerful combination of multiple data sources, a platform that can improve time/space sampling, real-time data synthesis and autonomous decisionmaking.” Indeed, the researchers are forthcoming with their analysis of the potential of this decision-making in applications beyond marine life
research. In their paper, they comment: “In oil and gas production, there is a need for constant monitoring of the marine environment for both chronic problems and acute effects such as drill cuttings, seeps and leaks. Vehicles could be configured to measure these plumes with fluorometric sensors and internally process data to build a real-time map of a given plume, constantly updating its navigational goals.” While an accurate example, we at InnovOil think this belies a wealth of further potential. Based on these principles (albeit with some innovation and the right equipment), AUVs could scan pipelines and subsea infrastructure for defects, triggering a secondary mission to capture highdefinition images or additional scans if they detect potential cracks or holes. A single mission could then provide engineers with enough detailed information to plan a repair accurately. Neither is it fantastic to imagine an NEWSBASE
AUV capable of surveying large areas continuously and comparing data against previous sweeps. If differences are found – e.g. if a pipeline has been unexpectedly moved or been damaged – the AUV’s additional mission could be to investigate further, within defined parameters again taking more detailed scans, images or to map the surrounding area. This could provide valuable information in real-time, without the need for additional or even remote human-controlled surveys. Similar analytical methods could even be applied to aerial vehicles such as drones. At the moment, these choices are fairly binary. As the researchers note, their system is based on collections of either 1’s or 0’s. But further innovation, as is already occurring across the field of robotics, is likely to mean even greater expansion of AUV capabilities. Moline and Benoit-Bird’s paper may be a small step for man, but it looks like a giant leap for autonomous robots. n
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No time like a crisis page 8
April 2016
Andrew Dykes reports from the Industry Technology Facilitator annual Technology Showcase in Aberdeen, where the focus was on increasing the speed at which the industry takes up new ideas
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O borrow a tired phrase: operators are from Mars; innovators are from Venus. At least, it often seems that way. But what sets the Industry Technology Facilitator’s (ITF) Technology Showcase event apart is its success in putting these two groups together – via a series of presentations, breakout sessions and a technology exhibition – providing equal balance to both the boardroom and the workbench. In recent months, ITF and other bodies such as the Oil and Gas Innovation Centre (OGIC) and Oil and Gas UK have launched a number of initiatives to get more technology developers in conversation and collaboration with operators, to generate new ideas to solve old problems. That conversation is lively, and
with developers travelling from as far afield as Australia, it is also of global importance. Upping the uptake ITF director Paddy O’Brien opened the conference with an emphasis on how it was seeking to “increase the speed of uptake,” and hinted at the launch of an exciting new technology “network.” Stay tuned for more. The first conference session tackled the North Sea, with the UK Oil and Gas Authority’s (OGA) director for technology, supply chain and decommissioning, Angela Seeney, outlining how it was working to encourage new technology development. Echoing similar demands from operators, the OGA is looking for innovators to show evidence which can build strong business
Technology Evolution
Mind the Innovation GapTHE INNOVATION GAP TECHNOLOGY EVOLUTION: MIND 1975 Argyll Field North Sea First Production
High performance water based mud
Offshore drilling 3D seismic
Jack up drilling Drill bits
4D Seismic
LWD
Innovation gaps
Technology milestone
3
N Estopped? WSBASE Innovation driven by necessity – why have we
cases in order to get their new technologies noticed. Her overall message was positive: with production efficiency rising to just under 80% in 2015, the outlook for UKCS production is improving steadily (even if prices are not). Building strong technology businesses now would help prepare UK industry to export its knowledge long after the North Sea has ceased production, she said, adding that the OGA’s goal was for the UK to become the second largest exporter of oil and gas services after the US (it is currently fourth behind Norway and France). Centrica senior VP Colette Cohen drew attention to the fact that the introduction of new technologies had largely stalled in recent, high-price years. The cushion and driver of bringing new production on line has meant that few – if any – so-called “technology milestones” have occurred since the price rises of the early 2000s, see graph below Cohen was evangelical about the possibilities of innovation from outside of the conventional envelope. While other sectors such as healthcare and automotive benefit from the internet of things (IoT), 3-D printing and advanced materials, oil and gas has been far slower at taking these up. The industry should “steal or adopt” these disruptive technologies, she said, because they “could be rapidly deployed if we stop thinking [the industry] is special or unique.” GE Oil and Gas director of subsea technology Paul White struck a similar note when asking if the industry was “risk-averse because we don’t understand the risks?” A
April 2016
greater focus on fundamental engineering may be one way to help change attitudes, he suggested, adding that while new technologies are no silver bullet, they are an incredibly valuable tool. It was refreshing to hear more figures looking to other industries for inspiration, and shows that the messages of previous Showcases are being heeded. Indeed, ITF’s director of strategic projects and international development, Keith Mackie, told InnovOil ahead of the event that “adoption and adaptation could be the watchwords” for a sector looking for new ways to cut costs. Innovators vs. investors With the operator and governmental perspective laid out, the second session sought to highlight various strategies which might help SMEs to bring their innovations to market, with some additional input from outside the industry. Scottish Enterprise’s Maggie McGinlay outlined firmer plans for the long-awaited Oil & Gas Technology Centre (OGTC), backed by US$180 million in government funding via the recent Aberdeen City Region Deal. This funding will help propel SMEs and service providers to develop their solutions and encourage an “early adopter culture,” and support the OGA’s export goal. For smaller innovators in particular, it is hoped that the OGTC will prove transformative, with McGinlay drawing comparisons between its role and that of the GBP2 billion (US$2.9 billion) Aerospace Technology Institute in Milton Keynes.
InnovOil
Magma Global commercial director Charles Tavner offered a balanced perspective through having worked both as an investor and as a SME technology developer – Magma manufactures carbon-fibre composite pipes for use subsea. His central message was that innovators must provide clear, robust business cases if they hope to gain traction with operators. Anecdotally, he said that many companies would be sceptical or unreceptive if an innovation did not offer cost savings of over 20%. Demonstrating a sound understanding of exactly how and where a technology can save money is therefore vital. Investors and operators should also take note. Tavner urged firms to find ways of accelerating technology adoption, in particular by committing to the early deployment of new equipment, and allocating enough funding to the project to make sure that happens. Yet in the current climate, he concluded, the opportunities for disruptive technologies with that robust business case behind them are “huge.” Well-SENSE technology director Dan Purkis posed some general thoughts on his approach to innovation, suggesting that it centres on the question: “What if?” Purkis suggested hypothetically removing existing, integral technologies with a view to thinking more clearly about how that process could be done better. In his case, it was with a company called Petrowell which used RFID tags to replace conventional measuring-while-drilling (MWD) solutions. He also offered a view from the other side of the boardroom door. As a technology NEWSBASE
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developer, he presented on the difficulties he had faced in convincing operators to back and deploy his technology, despite their enthusiasm and professed need for cost-effective solutions. In his experience, the biggest barrier lies in the reluctance of operators to qualify innovations in the field. The equipment then becomes trapped in doldrums, whereby operators neither take unqualified technologies, nor will they qualify it themselves using their own fields and wells. A lack of alternative testing facilities – or their prohibitive expense – also makes overcoming this hurdle particularly challenging. Purkis’ point sparked greater debate later in the Q&A session about how to share risk between operators and SMEs. It is hoped that the OGTC will remove many of these barriers by providing a network of solution centres, test facilities and incubator spaces where sufficient time and resources can be spent in qualifying innovations to the standards demanded by operators. That process is already under way, but is unlikely to produce results for at least a year or so. In the meantime, questions still remain over how larger companies can initiate a cultural change and accelerate adoption in the short term – questions which would continue to be hashed out over the rest of the day. Game-changers The afternoon was divided into four sessions, covering new technologies in the fields of Asset Integrity, Reliability and Production Efficiency; Well Plugging & Abandonment; Technologies for Marginal Developments and Small Pools, and Well Construction & Drilling Automation. These sessions featured short “elevator pitch” presentations on a number of potentially game-changing technologies across the set topics. InnovOil particularly enjoyed Interwell’s use of thermite as a P&A solution, the National Physical Laboratory’s work on digital image correlation for inspection routines and NeoDrill’s Conductor Anchor Node (CAN) technology for top-hole well construction, all of which used accessible, proven technologies to great effect. Stay tuned for more information in later editions. While the challenges – both physical and economic – remain great, ITF again has succeeded in proving that innovation is alive and well in the oil and gas industry. “This Showcase could provide the first steps towards addressing some of the key issues that keep the industry leaders awake at night,” ITF’s Keith Mackie remarked in the days leading up to the event. Let’s hope they have slept at least one easier night since. n
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InnovOil
On the radar
April 2016
What caught our attention outside the world of oil and gas this month
Engineers achieve Wi-Fi using 10,000 times less power
Nanomotors autonomously seek and repair cracks Researchers at the University of California in San Diego have devised a synthetic self-repair system for electronics using selfpropelled nanoparticles. These particles can autonomously detect and repair microscopic mechanical defects to restore the electrical conductivity of broken electronic pathways. These nanomotors are made of spherical gold and platinum Janus particles – particles with two or more physical properties, allowing different types of chemistry to occur on the same particle. They are powered by hydrogen peroxide, as the
platinum spurs the fuel to break down into water and oxygen, propelling the particles. In tests, these particles moved over the surface of a scratched and broken electronic circuit containing an LED. When the particles encountered the scratch they became lodged inside it and bridged the gap, completing the circuit and re-lighting the LED. Researcher Jinxing Li believes that these could be used to repair damage-prone electronic components such as conductive solar cells, as well as flexible sensors and batteries.
RFMOD comes home with magic beans A tiny bean-shaped sensor package from UKbased RFMOD holds a wealth of potential applications. Inside each of the 45mm by 18mm, 3-D printed “beans” is a small circuit and a wirelessly rechargeable battery. This powers a sensor array which can monitor an impressive amount of environmental variables, including motion, temperature, air pressure, humidity and even some gas concentrations such as CO or CO2. The device also features a compass and gyroscope to provide readings on its orientation.
Data can be collected by these sensors and sent to other IoT nodes via low-power Bluetooth. While the firm sees the potential in agricultural applications such as grain storage, there are almost innumerable possibilities beyond that, including wearable tech, control systems, asset and fluid monitoring and track-and-trace. BeanIoT also comes with a programmable app, meaning owners and developers will be free to let their imaginations run wild.
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A team from the US’ University of Washington (UW) has successfully engineered Wi-Fi ttransmissions using 10,000 times less power than conventional systems. Termed “Passive Wi-Fi,” the innovation is capable of transmission at bit rates of up to 11 Megabits per second (11 Mbps), the same as conventional 802.11b Wi-Fi signals. These can be decoded on any existing Wi-Fienabled device and, according to the team’s website, at ranges of between 30-100 feet (10-30 metres). While this bitrate is lower than the maximum speeds of other Wi-Fi standards, it is around 11 times higher than Bluetooth. It also uses 1,000 times less power than rival energy-efficient data transfer methods such as Bluetooth Low Energy and Zigbee. An 11-Mbps transmission consumed 49.28 micro Watts, according to the researchers’ website. The key to achieving this was in reconfiguring the analogue components, the most power-intensive part of a conventional Wi-Fi transmitter. In Passive WiFi, these highpower functions are all handled by a single mains-powered device which generates the signal, while passive sensors simply reflect and absorb that signal using almost no power at all. Passive Wi-Fi could enable major technological strides in sectors such as the Internet of Things (IoT), connecting devices which were previously too energy-demanding to afford power resources to conventional Wi-Fi. The team has suggested applications in monitoring systems such as microphones, cameras and proximity sensors. The team has also stated that tiny passive devices could be as cheap as US$1 to make, offering an incredible range of potential connectivity applications. Passive Wi-Fi is currently in the process of commercialisation by spin-off company Jeeva Wireless and could be seen on the market in the next 3-5 years.
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Google breaks with robotic arm Google’s parent company Alphabet is putting robotics subsidiary Boston Dynamics up for sale. The company has designed and built a range of autonomous robots, demonstrations of which have gone viral on the internet. But with most of its systems issued as part of military contracts, Boston Dynamics remains some way off a commercial product. In addition, Bloomberg reported there had been considerable internal strife over how the division was run and how it had interacted with other Google subsidiaries since its acquisition in 2013. For those reasons, Alphabet is now looking to sell. Toyota and Amazon have been tipped as potential buyers, though nothing has been confirmed.
Army engineers craft new fouling preventer Engineers at the US’ Picatinny Arsenal claim to have developed a new surface applicant which could prevent fouling in its weapons. The applicant, described as “durable solid lubricant” or DSL, prevents materials from sticking to a weapon’s surface. The lack of adhesion means that small vibrations, movement or recoil from firing is enough to knock any debris free. Applied at the manufacturing stage, it could allow the US military to produce corrosion-protected weapons which rarely require cleaning or lubrication. Patents are pending and further field tests will be conducted this summer, though the team hopes to begin production in 2018.
Right: The Atlas bipedal humanoid robot developed by Boston Dynamics
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April 2016
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ASSET INTEGRITY
April 2016
SPECIAL SUPPLEMENT Pages 13-21
CLEVER COATINGS
How Hempel can help protect asset integrity Page 14
HEED THE MESSAGE
Thoughts from Lockheed Martin’s forthcoming asset integrity report Page 16
BOLDLY GOING
Deep Trekker’s micro-ROV Page 20
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InnovOil
April 2016
Hempel coatings – integral to integrity ASSET INTEGRITY
Innovative coatings from Hempel help fight corrosion and protect asset integrity
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IL and gas assets are subject to some of the harshest working conditions any industry might face. Those environments and the increasing age of working stock present significant challenges to asset integrity professionals. Yet one of the discipline’s main tenets is that the prevention of damage is almost always better than the cure – and more often than not, coatings are the best way to meet that challenge. Hempel is a global coatings supplier for the decorative, protective, marine, container and yacht markets. It knows how harsh operating environments can be and has engineered a vast array of ways to help tackle one of the oil and gas industry’s greatest problems. Whether topside or subsea, its technologies help to protect vital assets from corrosion, abrasion and marine fouling. Corrosion resistance Of all the issues faced by operators, corrosion is one of the largest. It can take many different forms and can manifest itself as a variety of problems: • General uniform corrosion both internally and externally. • Corrosion under insulation (CUI) a specific problem in the case of insulated process pipework and vessels operating within a limited temperature range. • Thinning of structural elements leading to increased fatigue. • Bacterial corrosion on process vessel internals. Indeed, some extrapolated cost estimates from the US’ National Association of Corrosion Engineers (NACE) put the total cost of corrosion to US oil and gas companies at around US$1.3 billion per year, US$320 million of which is associated capital
Salt spray test
Zinc epoxy without Avantguard® technology (986 hours)
Zinc epoxy with Avantguard® technology (986 hours)
Full system without Avantguard® technology (1440 hours)
Full system with Avantguard® technology (1440 hours)
Hempadur Avantguard® 750 One of the key products in the Hempadur range is Avantguard 750. Based on activated zinc technology this product offers unrivalled corrosion protection for zinc-rich epoxy primers. Zinc epoxy primers remain one of the principle technologies for the protection of structural steel. The development of
activated zinc technology by Hempel provides greater protection to the underlying structure. In addition to this the product is much more tolerant to over thickness during application, in service degradation and can be applied in a wide variety of environmental conditions, unlike zinc silicates. All of these features mean that AvantGuard
expenditure. Choosing the right coating to protect an asset throughout the course of its life can therefore make a major difference to operators’ bottom lines. Hempel’s understanding of corrosion has led to a broad portfolio of protective solutions which can help to support asset integrity regimes, throughout up- and downstream operations. Hempadur One of the easiest ways to reduce the effect of unscheduled fabric maintenance is the specification of a robust protective coating at the new construction stage and ensure that it is correctly installed and maintained. Hempel’s Hempadur products are a range of epoxy coatings designed to protect steel NEWSBASE
can significantly decrease resulting maintenance costs for installations – especially for those difficult-toaccess locations, where maintenance and downtime are most expensive. Hempadur Avantguard® 750 based systems have recently been qualified to meet the requirements of ISO 20340 and NORSOK M-501 Edition 6.
from the harshest conditions. Covering both primer and intermediate coats, the main focus of the Hempadur range is to provide effective barrier properties from corrosive elements and is used widely in the protection of structural steel, pipework and storage tanks. For offshore assets, and in particular mobile production and drilling units, the ability to protect water ballast tanks and crude oil storage tanks is of critical importance. Premature breakdown of protective coatings in these areas is exceptionally costly to rectify given the difficulties associated with confined-space work offshore. The loss of storage capacity can have a significant operational impact on the facility whilst
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ASSET INTEGRITY
Versiline CUI 566990’s unique fibre reinforced filler makes the resulting coating highly resistant to micro-cracking after heat exposure thus eliminating potential sites for subsequent corrosion. maintenance work is completed. In these situations Hempel’s Hempadur XO Quattro series is an ideal material of choice. A two-component pure epoxy primer designed to protect water ballast tanks, cargo oil tanks and other immersed areas is available in a variety of grades. Its aluminiumfilled grades meet the specific requirements of offshore operators. Cracking is a common problem arising from application in difficult-to-reach areas commonly found in many tank arrangements and which is often a factor in premature maintenance. Hempel’s unique solution to this problem incorporates the use of fibres to offer increased mechanical durability and resistance to cracking due to over-thickness. Alternatively, both an aluminium-filled and fibre-reinforced grade can be selected for ultimate protection. Versiline CUI Whether onshore or offshore, complex process equipment is necessary during the extraction of oil and gas to make it suitable for transport and ultimately consumption. In many cases the thermal insulation used to preserve energy and protect personnel provides another major hurdle for asset integrity planning. Corrosion under insulation, or CUI, will almost always take place unnoticed until the area is inspected – which in difficult-to-access areas may be infrequently and costly – thus the prevention of CUI is always better than the cure. Again, selecting the correct coating at new construction can make a significant difference to downtime and associated costs later in the asset’s life.
Hempel’s Versiline CUI 56990 has been specifically designed to aid the prevention of CUI. Based on silicon, the copolymer coating cures to form an inert polymer matrix which provides long-term thermal and corrosion protection. A selection of barrier pigments – flakes of inert materials which prevent corrosive agents from reaching the metals – also help maintain its effectiveness. This means that Versiline CUI can withstand significant temperature variation and cycling, from cryogenic temperatures as low as -196°C and up to 650°C, and in dry or dry/wet use, and is suitable for carbon, austenitic and duplex stainless steels. Another of its advantages is that it can be applied to hot substrates, maintaining adhesion and its protective qualities at temperatures ranging anywhere from 10°C to 200°C. That allows operators to treat pipework on-site, and do so without a protracted cool-down period, saving time and money, and maintaining production. Condition monitoring In addition to supplying protective coating
systems Hempel is also able to assist customers with condition monitoring of protective coating systems already installed. Its team of trained coating advisors are able to carry out systematic inspections of whole or part process areas along with defect mapping and corrective recommendations where appropriate. Here Hempel is able to utilise its many years of coating supply into the maintenance industry to provide cost-effective recommendations which minimise surface preparation requirements so as to reduce impact on the customer’s operations. By working with an experienced coatings supplier, fabric maintenance professionals are able to access detailed coatings knowledge and expertise which might not be available within their own organisation / facility as part of their ongoing fabric maintenance plan. n Contact: Simon Daly,
Group oil & gas segment manager Email: SIDA@hempel.com Web: oilandgas.hempel.com
Maintaining hull integrity on floating offshore production units Hull inspection is an important element of fabric maintenance inspection for floating production units such as FPSOs. However, unlike conventional ships hulls and even mobile drilling units, once on station the opportunity for carrying out inspection at dry docking is
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rarely an option. Regulations require that an underwater inspection of the hull is carried out at regular intervals to compensate for this. Hempel’s range of anti-fouling products help facilitate that underwater inspection by reducing the level of fouling found on flat
bottoms, vertical sides, sea chests and other areas. Hempel offers a range of anti-fouling products from conventional self-polishing products to its class-leading fouling defence products based on Actigel technology, all designed to minimise organic fouling growth.
InnovOil
page 16
April 2016
ASSET INTEGRITY
Lockheed Martin surveys the asset integrity landscape A recent Lockheed Martin report explores technologies and techniques which could aid future asset integrity operations
F
ROM NASA equipment to canine corrosion detection, a new report by Lockheed Martin has left no stone unturned in its search for technologies which should be considered to help the oil and gas industry tackle the thorny issue of asset integrity. The Asset Integrity Landscape Study, commissioned by the UK Technology Leadership Board, Oil & Gas UK, the Oil & Gas Authority, Oil & Gas Innovation Centre (OGIC) and the Industry Technology Facilitator (ITF), evaluates the needs of operators, current state-of-the-art technologies and trends in other sectors in order to analyse which ones could have the greatest impact. At the time of the , OGIC
chief executive Ian Phillips commented: “The study is the first step in a project which will propose the adoption of new technologies, technologies from other industry sectors and the development of working methods where services can be combined in a logical, quicker and therefore cheaper manner. It will also propose the introduction of new products and services to lower costs and/or improve safety.” Lockheed Martin UK’s head of business development, Neale Stidolph, recently presented the company’s initial conclusions at an OGIC stakeholder event and at the ITF Technology Showcase. He outlined the group’s findings on the current state-of-theart for corrosion under insulation (CUI) and
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vessel inspection, as well as some left-field technologies which could play a role in future operations. These are each assessed via a spider graph, charting technology readiness level (TRL), benefits, applications, cost and risks. In introducing Lockheed’s analysis Stidolph’s first point was to create a triage procedure covering how the industry should examine the status of assets. By dividing them into three categories – “will die,” “might die” and “will live” – it can prioritise those that need the most urgent attention. These cases are where further inspection and/or repair and maintenance will have the greatest impact.
Prevention Looking at the prevention and detection of CUI, Stidolph assessed a number of potential solutions by their strength and readiness for deployment. Pulsed eddy current (PEC) – an electromagnetic technique which uses fluctuations in voltage to look for cracks and corrosion – was a front-runner, owing to its high impact and the fact that it is widely available. But lesser-known inspection techniques such as real-time radiography should also be of interest, as should microwave sensing, though the latter remains a mediumterm option rather than an “What we immediately deployable one. probably find is Further down the readiness that we need to scale but of immediate interest combine multiple are more esoteric solutions. Sacrificial wire may seem technologies” like an outdated approach Neale Stidolph, to prevention, but Lockheed Lockheed Martin UK’s believes that its low cost and head of business ease of deployment could make development it a solid solution. On the other hand, available products such as vapour-phase corrosion inhibitors (VCIs) – gaseous chemicals which offer long-term protection without an actual coating, by
April 2016
InnovOil
page 17
ASSET INTEGRITY Graphics from Neale Stidolph’s presentation at the ITF Technology Showcase 2016 Exhibition and Conference.
depositing a chemical film – are easy to get hold of, but in many cases suffer from a lack of trust within industry. Man’s best friend may have a role to play. Already a vital part of detection in military and security operations, sniffer dogs may be able to help oil and gas too. Backed by Statoil and Gassco, the Fjellanger Detection & Training Academy ran a project in 2013 which proved under double-blind conditions that trained sniffer dogs could successfully detect instances of CUI. Combining the results from multiple dog inspections then allowed engineers to categorise areas of high and low priorities, and rule out areas where no corrosion was suspected. However, that approach is unlikely to work everywhere – Stidolph pointed out that one might struggle to take dog teams offshore.
Inspection In process vessel inspections, far fewer techniques are at a stage of ready deployment. Though enabling platforms such as ROVs and AUVs have come on leaps and bounds in the past few years, the industry will probably still need a number of different types of vehicles to carry out thorough inspections – most of these are not yet capable of the delicate inspection or hazard avoidance that human operators offer; correspondingly, neither are many inspection techniques at the stage at which they could be automated. According to Lockheed, beyond these larger platforms the greatest technical priorities look to be phased array ultrasonic and low-frequency electromagnetic techniques. NEWSBASE
Terahertz spectral imaging, for example – a technique which uses the spectrum between microwaves and infrared, an “under-utilised” area Stidolph pointed out– has been used for metal integrity analysis in the civil engineering, nuclear and space industries. Yet although it offers the desirable ability to see through nonmetals, it will only show surface features and remains at a very low TRL to be used by oil and gas operators in the short term. Of course, the list is by no means exhaustive. During his presentation Stidolph also said that in many cases: “What we probably find is that we need to combine multiple technologies. We might use one innovation for some general signposting of a problem or corrosion precursors for instance, and then use a specific spot inspection technique to look in more detail.” While the report is only the first stage of a number of initiatives, many of which will be tied to work overseen by forthcoming Oil and Gas Technology Centre, it should help to expand operators’ horizons beyond the silo of oil and gas. The next will be to create a structure under which the technology providers and the asset holders can communicate effectively. If that is successful, InnovOil hopes to see more than one or two of these techniques offered commercially within the next few years. n Lockheed Martin’s full report on asset integrity in the North Sea will be made available via OGIC in late April.
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InnovOil
page 19
Watching assets like HAWX ASSET INTEGRITY
Xodus Group has launched an online tool to simplify the process of asset integrity management
A
CROSS the industry, operators and services firms are taking an increasingly proactive approach to asset monitoring. Better testing methods and substantially increased amounts of available data are enabling engineers to predict maintenance better and avoid infrastructure failure. With vibration, corrosion and erosion causing a sizable proportion of piping and pipeline failure, tracking fatigue and operating data on these assets is essential. Frequently, though, that data is stored in a spreadsheet, where it can be difficult to locate, interpret and share results within an organisation. Even then, the information that is there is not traceable. HAWXEYE is a new secure web application designed by Xodus to simplify the process of screening this data. Designed for use by upstream explorers, producers and subsea firms, its main benefit is that it allows operators to focus on investigating and preventing failures rather than locating and analysing data. Overseeing development of the system, HAWXEYE product manager and Xodus’ global lead for computational fluid dynamics, Mike Lewis – explained to InnovOil that it was originally devised as an internal tool to aid the company’s screening processes for new designs. Xodus has seen a need for HAWXEYE based on its involvement in a number of internal and external joint industry projects (JIPs). Users simply feed asset operating data and information from Piping and Instrumentation Diagrams into the program, where it is screened against
industry standards. HAWXEYE then calculates likelihood of failure (LOF) readings – a probability value based on industrial guidelines from the Energy Institute, DNV GL and NACE – and reports the information using a simple traffic light system, indicating any potential issues. By storing historical data throughout the asset’s life, the data can be used to inform ongoing asset integrity management and improvement programmes. Its design also alerts operators of any potentially poor design features in both the development and operations phases, allowing them to detect the root causes of piping and pipeline failures and monitor reliability. They can also prioritise time and capital in addressing the most pressing issues first, while remaining confident about the integrity of other areas.
As an online cloud-hosted tool rather than a local spreadsheet, that information can be accessed by anyone across an organisation simultaneously, or generated in the form of a report for external stakeholders, contractors and for HSE requirements. The data entered is then fully traceable. Xodus Group operations director Graeme Rogerson adds that: “HAWXEYE is fully scalable, from a single item to multiple assets and can be used by any organisation facing piping and pipeline condition issues in difficult to reach equipment, which is a costly issue for the industry. Its user-friendly interface makes the app instantly accessible for experts and non-experts alike.” Lewis suggests that future incarnations of HAWXEYE may include automated data entry, as well as a number of other tools currently used in-house by Xodus. For now, though, he that says feedback from the HAWXEYE test group has been good, and has proved encouraging despite the tough market. And if it proves successful, it could even signal the end for headache-inducing spreadsheets. n Contact: Mike Lewis Tel: +44 (0)207 246 2990 Email: mike.lewis@xodusgroup.com Web: www.xodusgroup.com/tools/hawxeye
NEWSBASE
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InnovOil
April 2016
ASSET INTEGRITY
ROV star from Deep Trekker
Compact, portable ROVs from Deep Trekker aid low-cost inspections
W
ITH all the complexities of oil and gas technology, it’s pretty refreshing to come across something that comfortably fits in a suitcase – and all the more so if it’s a unique micro ROV packed with innovative features. If that wasn’t enough, you can own one for roughly the same cost as a single day’s hire of a rival model. Based in Ontario, Canada, Deep Trekker designs and manufactures its own range of ROVs and pipe crawlers. With portability and affordability being its driving force, the company has produced some remarkably versatile, easy-to-operate vehicles (even InnovOil staff managed to get the basics within a few minutes). The firm’s flagship vehicle – the DTG2 ROV – is a case in point. Weighing just 8.5kg in air and fitting almost within a cubic foot, its size and manoeuvrability make it an ideal option for conducting hull, storage tank and infrastructural inspections, and a useful tool for any asset integrity regime. An in-built rotating high-definition (HD) camera in the centre of the vehicle provides a video feed to the screen/control pad – a familiar layout to anyone who’s held a gaming controller – while the pad also features a video output port to record footage or to view the feed on a separate screen. Two side-mounted thrusters give it a speed
of up to 2.5 knots. It uses these thrusters to dive and climb too, thanks to some clever engineering. By rotating the ROV’s entire outer shell while gravity holds down an internal semi-circular weighted frame, the main thrusters can rotate a full 180 degrees. With fully reversible thrust, the same system means thrusters can also move the vehicle forwards or backwards (though not side to side). Deep Trekker claims it can even be out of the box and in the water within 30 seconds. Different class The DTG2 is rated for work between 75m and 125m depending on the model. A straightforward Starter unit comes with a 50m tether and screen controller, while the Pro and Smart packages feature longer tethers and additional sensors. The Worker model has these capabilities in addition to a fully rotating grabber arm, auto-heading and depth. The ROV can be made even more versatile, given that Deep Trekker offers just about every conceivable marine attachment. New additions to the optional extras range include 4K cameras and diveable control systems, as well water and sediment samplers, NEWSBASE
cutters and even a thickness gauge for measuring wall thickness or corrosion. Crawler wheel attachments allow the DTG2 to track along hulls or structures – meaning operators don’t have to buy two different vehicles to carry out different inspections. Onboard lithium-ion batteries will run the ROV for between 5 and 8 hours on a single 90-minute charge. If you’re planning on being in the water longer, the company also offers a hybrid power cable via a 5-mm tether, affording limitless mission time while subsea. Its price point is persuasive too. You can get hold of a basic Starter package for just under US$5,000, while a Worker version costs less than US$12,000. Given that day rate hire might be around US$1,000 a day or higher, ROI is achieved in a matter of hours. Only a handful of other vehicles meet the same capabilities and price point – we’re looking at manufacturers like VideoRay, Teledyne Seabotix and the intriguing Trident design from crowd-funded OpenROV – but as more enter the marketplace, innovative micro designs represent a step-change in how operators look at inspection techniques. n
Raising standards Lowering costs
InnovOil
Raising standards Increasing safety Raising standards Lowering costs Lowering costs Increasing safety Increasing safety
April 2016
page 21
ASSET INTEGRITY Raising standards Lowering costs
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At MMI, we understand that asset performance and the risk of failure is key to effective and safe asset management. MMI provides pragmatic technical consultancy and engineering services to help our clients understand and minimise their asset downtime and through life costs.
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Manvel, Texas 77578, USA DUBAI@ALATAS.AE Houston Office, 22015, South Frwy. Ali77578, Free Zone Manvel,Jebel Texas USA - South, P.O. Box 263 007
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24/03/2016 11:14:05
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InnovOil
April 2016
Chevron fires up Gorgon Chevron has produced and shipped its first cargo from the LNG megaproject in Western Australia
C
HEVRON has announced first production from its Gorgon project, in Western Australia. The development, the world’s most expensive LNG plant at a cost of around US$55 billion, is late and over budget, and the start of production will provide further supply to a region already grappling with a gas glut. The US company celebrated the start on March 7. Its first cargo was shipped to Japan’s Chubu Electric Power on March 21. Gorgon, which is based on Barrow Island, off the northwest coast, will reach production of 15.6 million tonnes per year of LNG. The project also includes around 20,000 barrels per day of condensate production. The next two trains will start up at six-month intervals, the company said. The development includes the liquefaction plant, a carbon dioxide injection
project and a domestic gas plant that will be able to provide 300 terajoules (8.1 million cubic metres) per day of gas to Western Australia. Feedstock comes from the Gorgon and Jansz-Io fields, which are 130-220 km offshore. “We expect legacy assets such as Gorgon will drive long-term growth and create shareholder value for decades to come,” said Chevron’s chairman and CEO, John Watson. “The long-term fundamentals for LNG are attractive, particularly in the Asia-Pacific region, and this is a significant milestone for all involved.” Chevron also holds equity in the Wheatstone LNG project, with the company saying that more than 80% of its equity gas from these two developments was covered by sales and purchase agreements (SPAs) and heads of agreements (HoAs) with regional customers.
NEWSBASE
Chevron has a 47.3% stake in Gorgon and is the operator. ExxonMobil and Royal Dutch Shell each own 25%, while Osaka Gas has 1.25%, Tokyo Gas has 1% and Chubu Electric Power has 0.42%. Back on track While project economics are daunting for Gorgon, Tudor Pickering Holt (TPH) struck a bullish stance on the megaproject. A twotrain plant had been expected to start up in 2009 and cost US$10 billion under the initial
InnovOil
April 2016
plan, it said, while the final development has added a third train and costs have reached an anticipated US$55 billion. Work on Gorgon was “badly managed”, TPH said, but it now offers attractive cash flow. Contracts have been struck at attractive rates, it continued, royalties are only 10%, shipping costs to Asia are low and tax should not be payable for some years, based on the huge investments made. As such, TPH said at a price of US$60 per barrel, the netback from Gorgon should be around US$4 per
page 23
1,000 cubic feet (US$113 per 1,000 cubic metres). There has been speculation about the addition of a fourth train at Gorgon. While there appears to be enough gas in the region to make such a plan feasible, economics do not currently support such a plan. Chevron has said another 5.2 million tonne per year train could be built, using the 11 trillion cubic feet (311.5 billion cubic metres) of gas at the Chandon and Geryon fields. LNG production is ramping up, in
Australia and beyond. Australia Pacific LNG (APLNG) shipped its first cargo in January 2016. Two trains at Queensland Curtis LNG (QCLNG) were brought on stream in 2015. Chevron also recently confirmed that its Angola LNG project would be restarted in the second quarter of this year, while the first of the US LNG export projects, Cheniere Energy’s Sabine Pass, started in February. Wheatstone LNG is due to reach first LNG by mid-2017, while Shell’s Prelude project should also begin next year. n
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InnovOil
April 2016
COMMENTARY
Diamond and GE forge BOP deal Writing for InnovOil, Tim Skelton investigates an interesting new model for BOP services, and how it could be applied to other areas of the industry
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AST month, US rig operator Diamond Offshore Drilling announced an intriguing new working relationship with GE Oil & Gas covering blowout preventer (BOP) systems at its offshore drilling operations in the Gulf of Mexico. If the partnership proves successful it could provide a blueprint for other businesses in the industry looking to make efficiency improvements and deliver cost savings in the current cut-throat climate of depressed oil prices. In what the two companies describe as a “first-of-its-kind” contractual service agreement (CSA) for the offshore industry, Houston-based Diamond Offshore – which is majority-owned by the New York based conglomerate Loews – will transfer full accountability for BOP performance at its rigs to GE Oil & Gas. In effect, this will mean GE buying back the eight BOP stacks it supplied to four Diamond Offshore drillships currently operating in the Gulf, for a combined price tag claimed to be around US$210 million. The BOP systems will then be leased back to Diamond Offshore. Importantly, however, under this revised set up – dubbed the “Pressure Control by the Hour” model – Diamond will only have to pay GE for using the equipment during the hours when it is actually online and available to them. Downtime will no longer be chargeable. Compared with the cost of buying new, at US$40-50 million per stack, the model offers potentially large savings to operators. It is also a far cry from just a few years ago, when drillers were happy to pay for and install two BOP systems on a single rig, if only to avoid the possibility of downtime. GE said that this 10-year collaborative contractual service arrangement involving its engageDrilling Services™ showcased “a new way of thinking to drive continuous improvement in deepwater drilling.” Yet the
idea itself is deceptively simple. The service agreement will mean GE personnel working aboard the drillships, and being responsible for management of parts, overhaul and repair, continuous certification, data monitoring, and management of change for the pressure control equipment. Performance review This performance-based contract is in part made possible as a result of the massive scale of GE’s data collection abilities, including predictive analytics and continuous certification capabilities. These processes are already going on in installations across the world, as smaller sensors and larger processing power have allowed operators to capture substantial amounts of information (increasingly in real time). Under this partnership, Diamond will capture data using GE’s monitoring and analytics platforms and over time, as more data is collected, expects to be able to implement more condition-based monitoring and maintenance. By simplifying Diamond Offshore’s operations and optimising between-well maintenance, this should in turn result in great BOP system availability, by reducing both the frequency and duration of downtime – so much so that GE appears confident it can see a ROI based on a leasing model for its BOPs, and one which should provide a regular stream of income rather than the large up-front orders the industry has come to expect. According to company statements, the original idea came from Diamond Offshore, and it was the drilling contractor that first approached GE with its proposal. “Subsea equipment repair and maintenance is the single largest cause of non-productive time across our industry, resulting in great expense to both drillers and operators,” Diamond’s president and CEO Marc Edwards added. NEWSBASE
“The purpose of our new service model is to incentivise all parties to prioritise equipment reliability and availability for the ultimate benefit of our customers.” He elaborated on the issue in a GE blog, where he said that: “There is no other industry that would accept the type of performance reliability that we see in subsea stacks, which costs a lot of money for our clients. There’s significant unproductive time of the drill rig over the well.” He backed this up with some figures, suggesting that a typical deep-sea drilling rig is unproductive for around 10-12% of its time – most of which is caused by problems with BOPs – and ultimately adding up to around US$35 million lost time per year on just one deepwater well. Incentivising reliability, he noted in a video explaining the agreement, means “tying compensation to system availability.” Mutually beneficial Given ongoing tough times for the industry, it seems as if both sides are set to benefit from the agreement. For Diamond Offshore it is a
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COMMENTARY Left: Hornet BOP equipment on Diamond’s Hornet drillship Photo: Diamond Offshore Drilling Below: Diamond’s CEO Marc Edwards (left) with Chuck Chauviere, president of drilling systems at GE Oil and Gas
way to cut costs – dramatically if it no longer has to pay for downtime – and improve operational efficiency. For GE it represents a long-term investment in gaining market share and knowledge in the offshore sector. The data gathered from Diamond operations will also be valuable, enabling it to look at future technical improvements and predict patterns in use and maintenance. “My clients are applauding this deal,” Edwards has said. “They believe it will be material in driving nonproductive time out of deepwater drilling.” It should be noted that GE appears to be bearing the brunt of the risk under such a partnership, at least compared to a traditional service model. Yet being first to market with such an agreement has its advantages, especially in the current environment, and GE will be banking on attracting more costconscious customers to the service. If it proves a success it may spur the operators of other drilling rigs to tiake another look at the way they think about their own systems – particularly in the case of subsea equipment. From a historical
perspective, offshore oil service and completion equipment have traditionally been outsourced to specialised service companies, but the drilling contractors have generally owned and maintained the drilling systems themselves. There may be some reluctance on the part of other manufacturers, however, to sign up to agreements that require them to move towards a rent-and-maintain model, or in some cases to repurchase subsea equipment already sold to customers. Some of that difficulty is reflected in the above partnership: sources close to the Diamond Offshore deal with GE say it took a full eight months to negotiate. Yet evidently it can be done, and there is strong business and technology sense behind this kind of arrangement. A successful roll-out to customers could help others in the industry see the long-term benefits and adopt similar concepts. It is also proof that collaboration – a word overused and underdelivered in oil and gas – can be made to work within a business context. Indeed, there is no real reason why similar CSAs could not be applied more widely to NEWSBASE
other areas of the oil and gas industry. By transferring responsibility for equipment availability to those parties most able to identify and rectify potential breakdowns – i.e. the equipment manufacturers themselves – the production chain could be streamlined. That would allow for improved efficiency for all parties involved, and less time lost to costly, disjointed – and frequently unplanned – maintenance programmes. This is vital at a time when low oil prices have dramatically reduced margins and eroded profits, and is particularly the case at deepwater drilling installations where production costs are even higher. On paper, the new way of thinking could also have another beneficial knock-on effect. If the manufacturers are forced to guarantee that their products work effectively beyond the point of sale in order for them to get paid, then the onus will be on them to maintain product uptime insofar as is possible. This in turn could spark a new wave of technology and equipment innovations, benefiting the sector as a whole – a situation in which everybody wins. n
Saltel Expandable Steel Patch An enhanced Oil Recovery Solution Innovative setting process with high pressure inflatable packer contrasts with traditional cone setting Saltel Industries has developed, tested and successfully trialed the use of an expandable stainless steel Patch (steel tube + outer skin with a profiled sealing system) for perforation shut-off. Run on tubing or e-CTU, it is expanded downhole using an inflatable packer to create a high pressure inner lining inside the casing. Applications include water and gas shut-off, modifying injection profiles, and repairing short lengths of damaged or corroded casing. Benefits • A proven technology ( + 500 patches set worldwide since 2010 ) • 97 % Success ratio • Small run-in diameter, simple setting process • Minimum reduction in ID, Large through passage • A reactive skilled operations team available worldwide • Fast feasibility study, job evaluation and proposal • Patch availability : short lead times & fast setting www.saltel-industries.com/io1
www.saltel-industries.com/io1
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Statoil looks to take Snorre subsea Cost-cutting and a demand for longer field lifespan will see Statoil look for subsea solutions at Snorre C
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TATOIL is abandoning plans for a new platform at its Snorre field offshore Norway in favour of a subsea solution that should boost recovery and cut costs. While this looks to be a sensible move, it also appears that stern warnings from the Norwegian Petroleum Directorate (NPD) have also been heeded. In February Bjarne Bakken, Statoil’s vice president for the Snorre 2040 project, told Bloomberg that the company had decided against its plans to install a new drilling and processing platform at the field in order to boost its life expectancy. Instead, he said that Statoil intended to pursue a subsea alternative, which should lead to a cost reduction of 30-40% from an initial estimate of 40 billion kroner (US$4.7 billion). “We’ve concluded with our partners and the authorities that a subsea solution will have a larger economic potential than a platform solution,” he continued. Expectations Originally, it was estimated that the platform could bring in 300 million additional barrels, a figure that has since been revised to 200 million. Despite its lower cost, Bakken went on to say that it was expected that the subsea programme would achieve the same target or exceed it by utilising the two existing platforms on the field. “Both based on the market and further
design optimisation, we can improve this [recovery rate],” he continued. “We’re also working to raise the volume extracted – that’s one of the positive things with a subsea solution.” In November, Statoil executive Mette Halvorsen Ottoey told attendees at an energy conference that the Snorre 2040 plan was under consideration following a series of delays, and that a decision would be made before the following autumn. “We are doing everything we can to look at the costs at that one [platform], and we are also considering if there might be a solution to use subsea,” she continued. However, these comments came weeks after a warning from the Norwegian Petroleum Directorate (NPD) – the government agency that oversees the country’s oil and gas sector – which threatened producers that chose not to extract more costly barrels from their acreage with bans from future licencing rounds. “There are rights and duties associated with having a position on the Norwegian Shelf,” said Bente Nyland, the head of the Norwegian Petroleum Directorate, at the time. “We don’t want companies that skim the cream. We will be very clear on that when we now consider awards in the next licensing round.” Pressure Over the past few years, the Snorre 2040 plan NEWSBASE
has been pushed back several times as Statoil and its partners battled with the fallout of the collapse in oil prices. At the same time, the NPD has continually pressured for the project to go ahead, viewing it as a key part of Norway’s plan to offset declining production through enhanced oilfield recovery (EOR). This frustration prompted Oslo to warn the company could lose one of its Snorre licences if measures to improve output are not taken. Despite frequent calls from bodies such as the Norwegian Oil and Gas Association (NOGA), an industry organisation representing firms such as Statoil, Total and Royal Dutch Shell, for tax breaks and incentives, Norway’s government has refused to offer any stimulus to encourage exploration and production. Instead, it has repeatedly stated that costs should be cut wherever possible if firms wished to remain competitive. Statoil is now intending to make a decision on the development concept for the Snorre 2040 programme in the fourth quarter, with a final investment decision (FID) in 2017. At the same time, it has warned that there are “no guarantees” that it will come to fruition. With the project’s breakeven price point likely to be well above US$60 per barrel, there will be little appetite for a rapid conclusion. Further delays could well be on the cards, despite the NPD’s probable annoyance. n
InnovOil
A new axe to grind
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April 2016
Schlumberger’s AxeBlade* promises faster ROP and better durability
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N late February, Schlumberger unveiled AxeBlade*, a new ridged diamond element drill bit. Engineered by Smith Bits, a Houston-based manufacturer acquired by the services giant in 2010, the secret to its power lies in the precise geometry of the axe-shaped element. According to the firm, this axe-blade shape combines the shearing action of a conventional polycrystalline diamond compact (PDC) cutter with the crushing action of a tungsten carbide insert (TCI) roller cone bit. Suitable for any bottom hole assembly (BHA), Smith Bits’ product sheet suggests it is best deployed in medium to hard formations, with unconfined compressive strengths over 5,000 psi. The Axe* elements themselves are, the companies say, 70% thicker than conventional PDC cutters, giving the bit “increased frontal impact resistance.” In plain terms this should make it more durable, meaning operators spend more time drilling, less time swapping out bits and an overall saving on rig time. The Axe elements are then positioned across the bit. Their combined action of crushing and shearing allowing the system to achieve a greater rate of penetration (ROP) than a conventional PDC bit, using the same rpm and weight-on-bit (WOB). Company figures put this ROP increase at around 22%, though case studies in Texas unconventional basins suggest it could be higher. Because it requires less force to carry out the same job, it also means less overall torque and reactive torque fluctuation, and offers better control during steering and drilling curved wells. Its shape also allows for more efficient heat dissipation when drilling.
point load on the rock using the same WOB. achieved 27% higher ROP and a 20% The cone-shaped element offers greater reduction in torque for an interval above the resistance to both impact and wear, and Granite Wash in the Anadarko Basin. An is of particular use for operators in hard AxeBlade bit enabled Unit to drill over 3,000 or difficult-to-drill formations. Improved feet (915 metres) at an ROP of 95.54 feet (29 impact resistance also means metres) per hour, all of which helped reduced shock and vibrations on save almost 15 hours of rig time. the BHA. As US rig counts fall, many According to Schlumberger’s operators will be looking to field trials, the AxeBlade make a smaller number of rigs enabled a 29% improvement in more productive. Even in the ROP for an unnamed operator current climate, a near-30% Axe element in Texas’ Eagle Ford, drilling increase in ROP will be sure to from vertical to a 90° angle, before completing a lateral section for a total of 3,586 feet (1,093 metres). Another operation for Unit Petroleum
* Mark of Schlumberger
Sting in the tale Smith Bits also elaborated on the development of these elements. While much of the progress made in drill bit performance has been the result of changes in materials, it is encouraging to see a granular innovation such as element shape having a comparatively large effect. The Axe is an improved variant on the firm’s previous innovation, the StingBlade. This uses a conical shape to place greater
catch their attention. n More information on the AxeBlade is available at www.slb.com/AxeBlade
NEWSBASE
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The cut of one’s JIP
A number of JIPs have recently been announced to boost efficiency and lower the cost of subsea processing
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TANDARDISATION has long been discussed as a priority for the subsea sector, but has been left somewhat in the background as the industry battles to make other cost and efficiency savings. It is therefore encouraging to see DNV GL continuing to support further stages of a joint industry project (JIP) on standardisation for subsea pumping. Perhaps more encouraging is the backing from industry. Petrobras, Royal Dutch Shell, Statoil and Woodside have all signed on to the project, a confirmation that oil prices aside, production in their respective regions (Brazil, Norway and Australia in particular) will hinge on greater use of subsea developments. As Woodside’s VP of Technology, Sean Salter, explained: “The oil and gas industry needs to re-assess stand-alone host developments due to higher costs and look more closely at tie-back opportunities. Subsea processing technologies enable long distance tie-back opportunities for remote and marginal fields. Cost reduction through simplification and standardisation is key to ensuring application of these technologies.” DNV’s project – “Subsea processing – Standardisation of subsea pumping” – supports original discussions begun in 2014. DNV likened its approach to a “LEGO-brick” model, with a view to producing modules with standardised dimensions and interfaces. DNV says that this “increases predictability in the value chain, thus lowering transaction costs and improving the speed of implementation, while still allowing freedom to innovate and to employ new technology.” Petrobras Research and Development Center executive manager André Lima Cordeiro noted his company’s experience
with ground-breaking projects such as VASPS, MARLIM and MOBO, the latter being the first horizontal subsea electrical submersible pump (ESP) boosting module in the world. Although it has the backing of several major firms, DNV is still looking for additional collaborators and for suggestions of other subsea areas which may benefit from standardisation. Input from these parties will form the first phase of the project– developing a description of subsea pumping and possible targets for standardisation – before the second phase knowledge-sharing and the creation of best practice guidelines begins. All hands to the pumps Another, separate project, led by GE Oil and Gas, is looking to innovate in similar territory. In a February release GE Oil and Gas announced that it would explore “a new and simplified subsea boosting system that has the potential to reduce lifecycle costs by up to 30% and improve operational flexibility for operators.” Backed by Statoil, Total and two further operators, it said that its JIP would develop a “Modular Contra-rotating Pump (MCP),” drawing on technology from its aviation business. According to a GE release: “The MCP provides the potential to unlock and enable access to more oil in both new and mature wells in a simpler way by reducing the topside and subsea footprint by up to 50% and eliminating equipment such as the barrier fluid system needed in conventional subsea boosting systems.” Having already supplied boosting equipment to Statoil’s Snøhvit gas field, and having signed a master service agreement NEWSBASE
(MSA) for future contracts, it’s clear that GE is firmly involved in the Norwegian major’s subsea development plans. Meanwhile, on the other side of the world, Wood Group is embarking on a similar JIP to tackle subsea failure rates. Initial research for the Subsea Equipment Australian Reliability (SEAR) JIP revealed that five Australian fields had suffered more than 100 subsea failures over six years. Identifying and collaborating how to prevent or rectify these failures offers a solid chance of reducing intervention and expenditure. Wood Group Kenny CEO Bob Macdonald commented: “We are now asking vendors to come forward with technology solutions to help address the specific challenges faced in Australian waters. Of particular interest are novel coating technologies and materials which will improve the ease of equipment change-out and intervention campaigns.” While the support behind these projects is encouraging, standardisation initiatives offer greater benefits if a larger number of parties are involved – and if their end results are heeded. It is therefore important that the knowledge gained, whether in the North Sea or Australia, is shared as widely as possible, and that operators and supply chains make firm commitments to follow new guidelines. n For more information on DNV GL’s “Standardisation of subsea pumping” JIP, contact principal engineer, subsea technology, Kristin Nergaard Berg at: Kristin.Nergaard.Berg@dnvgl.com. To learn more about Wood Group’s SEAR JIP, contact co-ordinator Oddbjorn Gjerde, on: oddbjorn.gjerde@woodgroupkenny.com.
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Assuming the LOTOS position
April 2016
David Flanagan reports on Grupa LOTOS’ EFRA refinery upgrade programme
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S the upstream industry begins to crack under price pressure, refineries are heating up. One player on the up is Grupa LOTOS, owner and operator of Poland’s key Gdansk oil refinery, which has been implementing a farreaching upgrade and efficiency programme. The so-called EFRA project will see the group improve performance of the refinery through a number of technical innovations and improvements. In an exclusive interview with InnovOil, LOTOS president and CEO Pawel Olechnowicz gave an update of EFRA’s progress, and explained some of the motivations and key technological elements of the upgrade, and how LOTOS is ultimately measuring EFRA’s success. As with many European refiners, LOTOS’ plant expansion takes advantage of the current market and increasing throughput “to seize wider margins on higher volumes.” Olechnowicz explained the role of EFRA within the group’s long-term strategy, highlighting the “gradual modernisation of oil processing” which began with the “10+ Programme,” implemented between 2007 and 2010. It is an approach thoroughly rooted in technology, and based on the belief that using more advanced methods of processing each barrel will enable it to operate at maximum efficiency. But the regulatory climate is also a driving factor motivating some of these changes. He explained: “Growing environmental requirements and the increasingly stringent nature of EU regulations have an impact on the oil refinery sector in Europe. [Environmental responsibility] is an important part of our development programme, and one which triggers improvements in our refining technology.” WOW factor One area upon which EFRA has focused is hydrogen production. Olechnowicz pointed out that increased H2 output would deliver
significant commercial and regulatory benefits. “Due to the inclusion within EFRA of the Hydrogen Recovery Unit (HRU) – which we sometimes call by its Polish acronym ‘WOW’ – and of the Hydrogen Generation Unit (HGU), we want to achieve a situation where LOTOS will greatly increase production of hydrogen. In turn this will allow us to produce and de-sulphurise far more fuels.” Hydrogen is used in the hydrodesulphurisation and hydrocracking of crude oil, and the EFRA plan will see a major addition in capacity at the two existing installations for Diesel Hydrodesulphurisation and MHC Hydrocracking. “We expect this will deliver nearly 1 million tonnes of additional products obtained from heavy, high-sulphur residues,” Olechnowicz added – and higher volume outputs improve the firm’s refining and production margins. These technical changes should allow LOTOS to transform its product range with a number of new offerings. “Instead of asphalt and heavy fuel oil which we produce now, the installations will produce 900,000 tonnes of excellent, almost sulphur-free fuels that meet stringent environmental standards,” he continued. The new EU rules include the amended Industrial Emissions Directive (IED), known as the “NOx and SOx” directive, as it seeks to reduce emissions of nitrogen and sulphur compounds from the industrial and energy sectors. The upgrades mean that LOTOS should no longer encounter IED issues with regard to the sale of heavy fuel oil which either does not meet, or will soon fail to meet, standards for permissible emissions of sulphur compounds. Technologies for recycling and reuse have also been incorporated into NEWSBASE
EFRA; the by-products created during the heavy oil desulphurisation process will now be treated to yield pure sulphur, which can be sold to external customers and delivered in liquid form via tanker. Future flexibility As well as commercial and environmental benefits, EFRA is also intended to bring LOTOS greater flexibility. Olechnowicz noted: “The project gives us a greater competitive advantage, owing to the maximisation of processing depth and the elimination of negative-margin products which are manufactured from heavy residue.” Overall, “the change in product
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Left: Grupa LOTOS owns and operates Poland’s key Gdansk oil refinery Opposite inset: LOTOS president and CEO Pawel Olechnowicz
loading and transport are all carried out to above-standard environmental safety regulations. Levies on emissions mean that the higher capex cost for this technology is offset in the long run, ultimately meaning a lower cost for LOTOS.
structure will result in an increase in refining margin of approximately US$2 per barrel,” he said. Future flexibility is therefore the key to the EFRA process. “In practice it is a kind of ‘technology policy’ which is securing the future of the refinery for a possible period of economic downturn. The refinery will be able to weather any downturn thanks to higher refining margins as well as the flexibility in terms of our product portfolio, and also the type of crude oil which is processed.” In practice, it means LOTOS can maximise its margins using lower quality, lower price feedstocks, without sacrificing its end product. “For example,” Olechnowicz explained, “Throughput of cheaper, lowquality crude oil from Canada or Venezuela can now be undertaken.” To accomplish this, many other installations at the Gdansk refinery are also being upgraded. “The most important is the Delayed Coking Unit (DCU),” said Olechnowicz. “The entire coking complex will be built around the DCU, including the Hydrogen Generation Unit (HGU), Coker Naphtha Hydrotreating Unit (CNHT), LPG Installation (LPGTU), installation of logistics
and coke storage (CS-LF) and the Hydrowax Vacuum Distillation Unit (HVDU).” He is bullish on the capabilities and green credentials of the “environmentally friendly DCU technology.” In typical DCUs, the coke is ground with a water drill and discharged from the reactor together with water into an open concrete basin, where it is cooled down through partial evaporation of water. At the same time, hydrocarbons from coke are released into the environment. To accelerate drainage, the coke in the basin is poured using a crane dipper, crushed in another unit, and then transported via conveyor belts – all of which exacerbate the risk of potential environmental damage. Instead, LOTOS engineers took the decision to reduce the water pressure drastically before opening the DCU reactor, in order to achieve a maximum withdrawal of hydrocarbons before the coke-cutting process. This was done with a newly installed vacuum pump, which helps to decrease the amount of escaping steam and volatile hydrocarbons. In the next stage of the process, instead of an open basin for unloading and draining coke, a closed hermetic system will be used, meaning that unloading, transfer, storage, NEWSBASE
Reading the results The complexity of the overhaul means that LOTOS has many targets to consider in assessing the programme’s progress – and whether or not it has been a success. Olechnowicz explained how LOTOS reviewed EFRA and the overall performance of the refinery against the backdrop of oil market conditions: “In each investment project, its crucial element is the assessment of its effectiveness and the benefits it will bring to our company. The key is the profitability of raw material processing, measured in terms of throughput margin. It should be at a decent level, even in periods of economic downturn or sudden changes in prices, exchange rates or demand.” That is, of course, easier said than done. One notable metric allows the group to weigh up its technology strategy with market variables. Olechnowicz elaborated: “In our reviews we monitor financial results, namely measurable indicators which may justify changes in technological processes. For example, the investment being carried out in our refinery in coking processes will result in greater resistance to changes in oil prices.” Ultimately, he is evangelical about the transformative potential of technology in the refining sector, concluding: “Thanks to EFRA, LOTOS, with its level of complexity, energy efficiency, depth of processing, operational excellence and technological advancement, will be among the best in the world.” This is encouraging to see, especially given the downward trend of European refining over the past five years. But, as Olechnowicz notes, the real test of the EFRA programme will come as prices recover – here’s hoping that improvements in technology will continue to work for LOTOS in the years to come. n
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NEWS IN BRIEF
Rosneft quits talks to buy Trican’s Kazakh arm Rosneft has pulled out of negotiations to buy Canada-based oil services company Trican Well Services’ Kazakhstan business. Trican’s 2015 fourth-quarter report released February 24 noted the firm had “discontinued negotiations with Rosneft regarding the sale of the Kazakhstan business.” Debt-laden Trican is anxious to offload its international operations to concentrate on its home market, most recently selling its US fracking unit to Keane Group for US$200 million last month. Weak market conditions saw Trican’s international division, which includes operations in Kazakhstan, record a C$873,000 (US$646,000) gross loss in the fourth quarter of last year, down from a C$1.178 million (US$871,700) profit in the corresponding 2014 period. Last week, Trican confirmed receipts from the Keane deal would be used to pay down its considerable debt, which stood at round US$235 million after the transaction. Rosneft entered the picture in August 2015, when it bought Trican’s Russian pumping services arm for C$197 million (US$145.3 million). Rosneft expected the purchase to make its oil recovery, downhole and well cementing operations more efficient. The oil producer may have concluded that Trican Kazakhstan would add little to the expertise already gained from the Russian division, especially given the
downturn that has struck Kazakhstan’s industry in recent years. Kazakhstan’s ageing fields are steadily becoming less economic with the collapse in crude prices. National oil output fell by 1.2% in 2014 and 1.6% last year. On January 15, Kazakh Minister of Energy Vladimir Shkolnik told Novosti- Kazakhstan he expected output to drop by 3.1% this year to 77 million tonnes (1.55 million barrels per day). Confidence in the industry has eroded with the collapse of the tenge, which has lost half of its value against the US dollar since Kazakhstan’s central bank decided to move to a free float in August 2015. Astana is counting on the Kashagan project, the largest oilfield in the Caspian Sea, to revive industry fortunes. Kashagan was launched in 2013 but closed two weeks later when a major pipeline leak forced operators North Caspian Operating Co. (NCOC) to overhaul the entire project. The Kazakh government has said the field will be relaunched in December this year, although NewsBase believes this is unlikely. Edited by Joseph Murphy joem@newsbase.com
Lloyd’s Register releases drone guidance New guidance approach supports industry in the safe and effective deployment of next generation drone and unmanned aircraft systems (UAS) technology that can significantly improve productivity gains through reducing risk exposure, survey times and in-service
inspection costs of offshore, marine and onshore infrastructure. ‘Eyes in the sky’ technology opens the way to rapid, safe and repeatable inspections that will lead to long-term benefits for energy and marine operators seeking high levels of integrity, compliance and commercial advantage. Lloyd’s Register’s first phase of its guidance notes for drones and Unmanned Aircraft Systems (UAS) is launched today, giving operators in the energy and marine industries confidence in using UAS for offshore, marine and onshore surveys and in-service inspections. “We are developing these guidance notes to provide a consistent approach to risk in UAS and drone deployment, offering practical operational considerations relating to regulations, personnel, quality, safety, hardware, software and operations,” says Lloyd’s Register’s Chief Technology Officer, Nial McCollam. McCollam highlights: “Technology and innovation in the area of digital data, sensing technologies, unmanned systems and robotics are here to stay. We see an exciting and important journey ahead, and anticipate our efforts to increase and continue.” UAS, commonly known as drones, provide an effective alternative to traditional methods of in-service operational assessment and survey, especially structures and assets at significant heights, difficult to access locations and hazardous environments. Major operators such as Shell and Maersk Drilling are among early adopters of innovative technology with safety and quality as a priority. The guidance notes from Lloyd’s Register will be updated regularly to provide industry with the latest practical information on issues such as how best to use UAS for inspection in confined spaces which is particularly relevant in energy and marine applications where Class surveys are needed, and which also improves safety for human life. You can find out more about Lloyd’s UAS work with industry at: info.lr.org/unmanned-aircraft-systems. LLOYD’S REGISTER
Topaz Energy wins new Caspian marine contracts from BP UAE-BASED Topaz Energy and Marine said last week that it had secured contracts from an arm of BP for the use of support vessels NEWSBASE
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in the Azeri section of the Caspian Sea. In a statement, Topaz said that the contracts covered 14 offshore support vessels that BP Exploration (Caspian Sea) has been using at the AzeriChirag-Guneshli (ACG) and Shah Deniz fields, both of which lie offshore Azerbaijan. They provide for the BP affiliate to make use of the ships for five years, with the option to extend for two more one-year periods. “The agreement extends currently running contracts for the 14 vessels until 2023, including all options,” the statement said. It noted that the deal covered emergency response and recovery vessels as well as large anchor-handlers and platform supply vessels. “These contracts bring Topaz’s global revenue backlog to nearly US$1.4 billion and [demonstrate] the company’s competitiveness in the Caspian market,” it added. To date, it said, Topaz has supplied a total of 21 vessels for use in the Azeri offshore zone. The company has been active in the region for several decades. Topaz did not reveal the value of the deal with BP Exploration (Caspian Sea), but Rene Kofod- Olsen, Topaz’s CEO, expressed satisfaction with the new contracts. “We are humbled by BP’s continued trust in our capabilities and look forward to repaying that confidence by consistent worldclass service,” he
said. “Our ability to secure long term contracts with a reputed oil major such as BP reflects the value and quality of Topaz’s operations in the Caspian and globally.” Kofod-Olsen also stated that the company was optimistic about expanding its operations in the Caspian Sea region. “Our exemplary operational and safety track record and our commitment to Azerbaijan allow us to build our position in the face of a challenging market,” he said. “The agreement provides a long-term platform from which to build further scale in the broader Caspian.” Edited by Joseph Murphy joem@newsbase.com
PetroChina establishes first gas pipeline joint venture Petrochina, the country’s largest owner and operator of gas pipelines, has set up a joint venture with Chongqing Gas, ushering in China’s energy infrastructure ownership reform.
NEWSBASE
PetroChina will invest 178.5 million yuan (US$27.4 million) in the new 51:49 venture, while Chongqing Gas will stump up 171.5 million yuan (US$26.3 million). The joint venture, the first of its kind in China, will be responsible for building and operating pipelines in the southwestern city of Chongqing. It will also be tasked with opening up its network to third-party access. PetroChina owns and operates about 77,000 km of onshore pipelines, 80% of the country’s total, most of which are gas pipelines. Spinning off the state major’s pipeline assets from its core oil and gas exploration and development business comes under the company’s ongoing reforms. In 2015, PetroChina decided to merge three gas divisions – Eastern Pipeline, Northwest United Pipeline and PetroChina United Pipelines – into a single specialpurpose company. PetroChina will hold a controlling 72.26% stake in the new corporate vehicle, PetroChina Pipelines, with 27.74% held by New China Life, Taikang Life, Guolian Fund, China’s National Social Security Fund and Youngor Group. Building pipelines in Chongqing is
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NEWS IN BRIEF
Shanxi targets shale gas opportunities
part of the local government’s strategy to increase the municipality’s gas production to 20 billion cubic metres by 2020. The government intends to spend up to 4.7 billion yuan (US$721.2 million) on constructing 11 shale gas pipelines in the city by 2020. The pipeline system will have a total length of 1,169 km with annual throughput capacity of 19.4 bcm. The Ministry of Land and Resources (MLR) pegs Chongqing’s shale gas reserves at 2 trillion cubic metres. Edited by Andrew Kemp andrew.kemp@newsbase.com
MCE wins riser modules contract Australia’s Matrix Composites & Engineering (MCE) revealed last week that it had won a contract to supply drilling riser buoyancy modules for a rig under construction in Dalian, China’s northernmost warm-water port. Under the contract, MCE is slated to deliver the modules to a shipyard for installation in a newbuild semi-submersible rig. The rig is now under construction at a shipyard in Dalian owned by a major original equipment manufacturer (OEM) based in China. It is due to be completed and delivered in the first half of 2017. In its statement, the company did not identify the OEM or name the end-user of the rig. It did say, though, that the deal was worth around US$4.4 million. Meanwhile, the Australian company’s CEO, Aaron Begley, touted MCE’s success in striking an agreement with a new customer. “I am delighted we have been able to secure this contract to supply a new customer, which is also Matrix’s third major order ultimately destined for a Chinese shipyard,” he said. “Our ability to win new
clients and continue growing market share in the depressed oil price environment demonstrates our reputation as the clear leader for drilling riser buoyancy products.” Begley’s remark highlights one of the difficulties facing the Chinese shipbuilding industry. When oil prices were still high, both state-owned and private shipyards began turning out rigs on a speculative basis, without first signing sales and purchase contracts. They did so on the assumption that prices would remain high enough to support demand for drilling equipment. After oil prices began collapsing in mid2014, however, interest in newbuilds among potential buyers diminished. As a result, a number of shipyards now have a surplus and have had to resort to cutting prices to attract customers. Edited by Andrew Kemp andrew.kemp@newsbase.com
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Northern China’s Shanxi Province, the country’s top coal producer, wants to push ahead with shale gas exploration as it comes under pressure to curb pollution levels. Shanxi Coal Geological Bureau, in partnership with two local energy firms, has recently wrapped up a study of the area begun in 2013, an official at the provincial land and resources department told Xinhua Finance Agency last week. It concluded that the province housed an estimated 4.44 trillion cubic metres of shale gas. If accurate, this would equate to 14% of China’s overall technically recoverable reserves of 31.5 bcm, as per the US Energy Information Administration’s (EIA) most recent estimate. The survey showed that the Ordos and Qinshui Basins, the former already a major production centre for conventional gas and coal-bed methane (CBM), were also rich in shale deposits. Further research will be used to identify sites for commercial exploration, the official said. Shanxi, which accounts for more than a fourth of China’s total coal supply, is looking at ways it can diversify its economy in the face of low commodity prices. Many of its mines have become lossmaking, prompting the central
Shanxi Province
page 36
InnovOil
April 2016
NEWS IN BRIEF
government to order the province to slash production. Yields fell to 944 million tonnes in 2015 from 976 million tonnes in 2014. As part of its clamp-down on pollution levels, Beijing is also trying to wean the country off coal and encourage the use of cleaner fuels, especially gas. Despite having significant shale gas reserves, China’s progress in developing these resources has been slow, as a result of factors such as water shortages, geological complexities and a poorly equipped service industry. In December 2015, Bloomberg reported that China would miss its output target of 6.5 bcm for 2015 by more than 1 bcm. Beijing currently forecasts shale gas production to hit 30 bcm per year, after halving an earlier estimate. Edited by Anna Kachkova, annak@newsbase.com
CNPC to spin off oilfield services division China National Petroleum Corp. (CNPC) could shed part of its oilfield services arm as part of the company’s efforts to shore up its balance sheet and boost efficiency. At the IHS CERAWeek conference in Houston, Bloomberg quoted CNPC chairman Wang Yilin as saying that his company was mulling an initial public offering (IPO) for its service segment. The timing and size of the offering was not specified, however.
As part of major economic reforms, Beijing is trying to loosen the grip of its oil giants on the country’s energy sector by ordering them to sell off assets. In December 2015, CNPC subsidiary PetroChina unloaded a 50% stake in the Trans-Asia Gas Pipeline (TAGP) network in a US$2.4 billion move to bolster year-end profits. In 2014, rival Sinopec agreed to shed part of its sales-and-marketing unit. The government is reportedly looking to strip both companies of their domestic pipeline networks. CNPC is the only one of China’s big Three Oil firms to still retain full control over its oilfield services business. China National Offshore Oil Corp. (CNOOC) floated shares in China Oilfield Services Ltd (COSL) in 2002 while Sinopec Oilfield Service was sold off in 2014. China’s efforts to allow the market to play a greater role in the industry have had mixed results. The sale of 30% of Sinopec’s retail business in 2014 raised 107 billion yuan (US$16.4 billion). But many investors who took part in the IPO were government-backed funds. Just before it was sold off, Sinopec Oilfield Services became entangled in Beijing’s anticorruption probe, which led to its general manager, Xue Wandong, being detained. In the end, Sinopec decided to sell the company to its Hong Kong-listed polyester maker, Sinopec Yizheng Chemical Fibre. This ensured the latter was not at risk of being delisted under exchange regulations after posting several annual losses. Instead of a private investor, the stake in TAGP was passed to another state-run
entity, China Reform Holdings (CRH), which Beijing established five years ago to facilitate the restructuring and consolidation of stateowned enterprises. Attracting investor interest in CNPC’s oilfield services division could be a tall order. The sector has been hardest hit by the collapse in oil prices, as producers have responded by curbing drilling plans.The unit posted 110 billion yuan (US$16.8 billion) in revenues for 2014, according to Bloomberg. This compares with 94 billion yuan (US$14.3 billion) and 33 billion yuan (US$5.04 billion) in sales made by Sinopec Oilfield Service sand COSL respectively. Edited by Andrew Kemp andrew.kemp@newsbase.com
Harkand to support start-up work for Maersk Harkand has been awarded a multi-million pound contract with Maersk Oil North Sea UK Ltd to deliver subsea support services to the operator including a commissioning support campaign for the Flyndre development located in the south-eastern part of the Central Graben Basin in the North Sea. The Aberdeen office of the global inspection, repair and maintenance (IRM) company will oversee the mobilisation of its sister dive support vessels the Harkand Atlantis and Harkand Da Vinci. The Flyndre campaign will see personnel carrying out choke valve replacement work as well as delivering umbilical tie-in operations. HARKAND
Exmar drops Caribbean FLNG plans EXMAR has dropped its plans to send its Caribbean FLNG vessel, which is under construction in China, to Colombia, as market conditions mean the project is no longer economic. In March 2012, Exmar and Pacific Exploration and Production (PEP) agreed to a 15-year deal to deploy the floating LNG (FLNG) vessel to Colombia. The two parties have agreed to a settlement whereby PEP NEWSBASE
April 2016
InnovOil
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NEWS IN BRIEF
something that can replace Malampaya. So, to bridge the gap would require LNG imports,” he added. The Philippines’ first LNG regasification facility – the US$800 million Energy World terminal – is being completed in Quezon Province, on Luzon. It is scheduled to come on stream later this year or next year, which is at least two years behind schedule. Edited by Andrew Kemp andrew.kemp@newsbase.com
will make payments to Exmar in monthly instalments until June 2017. Exmar intends to redeploy the vessel to other markets, particularly to companies working “in West Africa and the Middle East”, according to the company’s CFO, Miguel de Potter. De Potter told LNG World Shipping that Caribbean FLNG was “96 to 97 percent completed and will be commissioned one month from now”. Interest is now focused on Equatorial Guinea and Iran. The vessel has a liquefaction capacity of approximately 500,000 tonnes per year of LNG. By virtue of the settlement agreement, as of March 3, 2016, any and all obligations in connection with the tolling agreement have been terminated. The cancellation of the project appears to have been driven by PEP’s overall financial difficulties. Suffering in a weak market, PEP had made multiple announcements throughout the end of 2015 and into 2016 that it was “actively working” with its noteholders, lenders, and legal and financial advisors to restructure and extend repayments. The FLNG market has also deteriorated. Caribbean LNG is just one of a number of projects that have fallen through in recent months as a result of the commodity price downturn. In February, Malaysia’s Petronas announced it would defer the delivery of its planned PFLNG 2 unit as part of a US$12 billion-plus budget cut. Oslo-based Hoegh LNG Holdings also announced in February that it was putting its FLNG business on hold, allocating its resources and capital to its floating storage and regasification unit (FSRU) work, owing to the oversupplied LNG market. Edited by Ryan Stevenson ryans@newsbase.com
Shell targets 2017 for FID on Philippines FSRU Shell Philippines is finalising the technical aspects of its front-end engineering and design (FEED) study on the construction of a planned LNG terminal in the country. A final investment decision (FID) may be taken in 2017. Shell Philippines Exploration’ managing director, Sebastian Quinones, said Batangas Bay, on the main island of Luzon, near Manila, could be the site of a floating storage regasification unit (FSRU). The official said the company needed to iron out details of the FEED before reaching an FID. Quinones said investors and company shareholders would only approve the project if there was a “good and viable plus-minus 10 percent estimate” on the total project cost. “Probably, this would be hundreds and hundreds of millions again,” he said. “I don’t think [the final decision] will be this year. It could be next year.” The Philippine Star said supply from the Malampaya deepwater gas-to-power project was projected to run out by 2024, building an LNG import terminal would help overcome any shortfall. Quinones said that once the FID was issued, it would take less than three years to install the FSRU terminal. The Malampaya field supplies three gas-fired power plants on Luzon, the country’s most populous island, providing 40-50% of the island’s power generation needs. “Energy projects like this take a long time. Remember, Malampaya took a decade ... that’s why we are already preparing for LNG as a fuel source to replace Malampaya,” Quinones said. “Hopefully, we can find something in between but now it’s too late to be able to develop NEWSBASE
Fraunhofer-IOSB tests AUV at PLOCAN test site In March the Fraunhofer Institute of Optronics, System Technologies and Image Exploitation (IOSB) in Germany tested the DeDaVe, a new autonomous underwater vehicle (AUV), at the PLOCAN Test Site. The prototype AUV, built with German technology, is able to dive and operate completely autonomously down to 6,000 metres depth. It is also capable of carrying a diverse payload of sensors and measurement instruments suitable for tackling various types of mission in the fields of oceanography, hydrography, geophysics, and search and location, among other important applications. A multidisciplinary team of technicians came from Germany to carry out the work at PLOCAN’s land-based facilities and in the PLOCAN Test Site off the coast of Telde. The main objective of the trials was to validate the features and capabilities of the new device in deep water, in preparation for its commercialisation in the near future. Fraunhofer-IOSB is a world-renowned centre for the research and development of innovative concepts, methods and systems for industry, small and medium-sized businesses, and publicsector clients. PLOCAN
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InnovOil
April 2016
NEWS IN BRIEF
IWCF launches first free training for basic well control awareness The International Well Control Forum has launched a global online training course which will be free to everyone in the industry to increase knowledge around what can cause a well blow-out and potential oil spill incident. The interactive e-learning has been developed in response to the International Association of Oil & Gas Producers (IOGP) recommendations following the Macondo well blow-out which stated an introductory level 1 awareness training should be introduced. IWCF is the first organisation to achieve this and is offering the course free of charge through its website, supporting the organisation’s aim to increase competency and change behaviour in this safety-critical operation. IWCF already offers the higher levels, 2, 3 and 4, which are targeted specifically at those involved with well and drilling operations, but plans for the new level 1 training to be accessible by everyone with an interest in the industry. David Price, CEO of IWCF said: “It is important to us, particularly in the current climate within the industry, to give something back and by making this training readily available we believe that it will help to increase understanding of how well control events can occur and their consequences and prevention. “The training is open to everyone, it is specifically aimed at those in the industry with a secondary involvement in well operations but students considering a career in oil and gas or anyone else with an interest in the industry will also find it insightful. Ultimately, we want to see an increase in well competency which will improve offshore safety.” IWCF
BGS scientists find new way to lower fracking risk
recover gas and oil from shale rock may have the support of industry, but it has become a highly controversial subject in the UK. The fracking-generated tremors near Blackpool in 2011 intensified the controversy about this drilling process. Because of these tremors, the UK government commissioned an expert panel from the Royal Society and Royal Academy of Engineering to study the safety of fracking in the UK. BGS was selected to examine the stress data for the UK, after the panel recommended that a review be carried out. After it completely overhauled the existing data for the UK, BGS suggested that borehole imaging tools be used to log new boreholes drilled for shale gas. This process would help increase understanding of in-situ stress. Mapping of the UK in-situ stress orientation was difficult to do more than 20 years ago because the data and state-of-the-art technology were limited at the time. Over the period, the coal and oil industries started gathering borehole imaging data that scanned the entire inner circumference of the borehole. This method led to the identification of zones of the borehole wall that are widened by in-situ stress (borehole breakouts). The new data permit clearer images of breakouts. This in turn allows for interpretation of much smaller features, which enable breakouts to be identified in many more wells under UK stress conditions, the study suggested. Examining data from more than 90 of these boreholes from the coal and oil industries, the BGS team identified features in 37 of these that run from Peak District to the Scottish border. The scientists compared the new data with the 1990s data, decreasing the uncertainty of borehole breakouts. This new research can support assessments of in-situ stress orientation, which will give regulators examining well safety access to the best data to make properly informed decisions about borehole integrity, the BGS said. Commenting on the results of the study, BGS Director of Science and Technology Mike Stephenson said: “This research is crucial to the
BRITISH Geological Survey (BGS) scientists last week unveiled cutting-edge research that could mitigate the risk of earthquakes and borehole damage caused by hydraulic fracturing. This process of drilling down into the earth to NEWSBASE
regulators and the oil and gas industry, as it is an easily applicable technique that can highlight parts of boreholes that may contain evidence of stress that is already present in rocks before fracking.” Edited by Anna Kachkova annak@newsbase.com
ABB to provide equipment and services for Prelude ABB has won a five-year contract to deliver equipment and services for Shell’s Prelude FLNG, the world’s first floating liquefied natural gas (FLNG) facility, the largest floating facility ever built. ABB’s equipment will minimize downtime and optimize the efficiency of the facility. The order includes the delivery of motors, generators, variable speed drives and lowvoltage switchgear and guarantees service and lifecycle management of the electrical equipment as well as service and support for motors from third-party vendors. ABB will build up a spare parts inventory, workshop repairs, training and provide roundthe-clock technical support both over the phone and on-site. Spare parts and replacement systems are being procured this year, with training to begin soon after. Prelude is 488 meters long, 74 meters wide, with a loaded displacement of 600,000 tons with the facility’s deck longer than 4 football fields laid end to end. The electrical system will power 14 gas plant modules, allowing the facility to produce 5.3 million tons per annum of liquids. The agility of FLNG allows oil and gas companies to develop fields that would otherwise be uneconomical and their environmental impact is minimal compared with conventional production platforms and pipelines. ABB
April 2016
InnovOil
What next …?
To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections If you would like to learn more about how Hempel coatings can help to protect your assets, contact Group oil & gas segment manager Simon Daly via SIDA@hempel.com or visit oilandgas.hempel.com If you are interested in enquiring about Xodus’ HAWXEYE application, contact Mike Lewis on +44 (0)207 246 2990 or at mike.lewis@xodusgroup.com Lockheed Martin’s Asset Integrity report will be made available via the Oil & Gas Innovation Centre (OGIC). You can contact OGIC for further information at info@ogic.co.uk or call on +44 (0) 1224 444000 For more information about Deep Trekker and its range of innovative ROVs, contact sales@deeptrekker.com You can reach SeaCaptaur for additional insight into its storage, processing and delivery systems for small pools development on +61 (08) 9227 5247 or email alan.r@seacaptaur.com.au To hear more from Schlumberger about the AxeBlade ridged diamond element drill bit, contact corporate public relations manager Susan Ganz at sganz1@slb.com For more information on DNV GL’s “Standardisation of subsea pumping” JIP, contact principal engineer, subsea technology, Kristin Nergaard Berg at Kristin.Nergaard.Berg@dnvgl.com To learn more about Wood Group’s SEAR JIP, contact co-ordinator Oddbjorn Gjerde, on oddbjorn.gjerde@woodgroupkenny.com
NEWSBASE
page 39
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InnovOil, from the NewsBase group, is a technology-driven, monthly magazine which aims Andy Hill, Group Marketing Manager to provide a platform for innovators and engineers to share to share their ideas and expertise. IPU Group Our publication remains a trusted, solicited information source for technology news across the complete spectrum of the upstream, midstream and downtream oil and gas sectors. “We were pleased with the
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