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Bringing you the latest innovations in exploration, production and refining Issue 26
August 2015
Top technology from Teledyne Page 12
Finding the source GPUSA’s Distributed Seismic Source™ Page 6
Human or robot? The latest advances in inspection and maintenance Page 26
Controlling an FPSO ICSS from Kongsberg Maritime Page 16
t n e m le p p u S l ia c e p S
Out here experience counts
Visit us at Offshore Europe, Aberdeen 8-11 September, Stand 1B 81 25 years of dedicated printed circuit heat exchanger manufacturing for the oil and gas industry When you choose a heat transfer solution for the world’s harshest environments, track record matters. No-one understands printed circuit heat exchangers (PCHE) like Heatric because we invented them. Our pioneering research created the very first PCHE and we’ve been refining and developing the technology ever since. Today, a Heatric PCHE combines the highest possible integrity, performance and safety in a diffusion-bonded unit that is up to 85% smaller and lighter than conventional heat exchangers. Around the world we are providing efficient, reliable and robust service on fixed and floating oil and gas platforms in all the major fields. Our 10,000m2 of specialised manufacturing facilities is focused solely on PCHE production and testing. From concept design through to final delivery, Heatric’s world-leading PCHE engineering, project and manufacturing teams can provide you with the best possible service and a tailored heat transfer solution that closely matches your particular operational needs. At Heatric we provide the highest quality PCHEs and the peace of mind of knowing that for a quarter of a century our technology has been reliably and efficiently meeting the toughest of challenges.
Heatric. Leading heat transfer solutions www.heatric.com
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info@heatric.com
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T: +44 (0)1202 627000
InnovOil
August 2015
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Inside Contacts: Media Director Ryan Stevenson ryans@newsbase.com
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The next generation
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Ultra-marine
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The Full Picture
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Keynote speaking
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Beyond “Wraps”
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Charles Woodburn, technical chairman of SPE Offshore Europe 2015 and Expro CEO, discusses the future of industry technology and skills
Media Sales Manager Gary Paterson garyp@InnovOil.co.uk
Technology from Teledyne Marine Systems enables a low-logistics, unmanned approach
Design & Web Dan Bell Danielb@newsbase.com
KONGSBERG’s integrated control and safety systems (ICSS) allow operators to control complex production facilities.
Editor Andrew Dykes andrewd@newsbase.com
Offshore Europe’s keynote chairman, Michael Engell-Jensen, talks to InnovOil
NewsBase Limited Centrum House, 108-114 Dundas Street Edinburgh EH3 5DQ
IMG Composites’ Ian Taylor discusses the problem with composite ”Wraps”
Phone: +44 (0) 131 478 7000 www.newsbase.com www.innovoil.co.uk
Johan Sverdrup explained 24 Exploring the contracts behind Statoil’s Johan Sverdrup megaproject
Design: www.michaelgill.eu ™
and refining August 2015
Issue 26
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top technology From teledyne
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2014
Finding the source
GPUSA’s Distributed Seismic Source™ Page 6
l ia ec sp
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Patent innovation
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Big Foot in big trouble?
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News in brief
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The trends driving new oil & gas patents and how lower prices may affect them
Page 12
human or robot?
Robotics autonomous
Advances in automation and robotics are changing the way the industry looks at maintenance and inspection
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ction ations in exploration, produ Bringing you the latest innov
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Seismic shift
Offshore Europe 2015
Media Sales Manager Riley Samuda RileyS@InnovOil.co.uk
The latest advances in inspection and maintenance
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GPUSA’s Distributed Seismic Source™ for marine and downhole applications shatters conventional wisdom
Associate Director of Business Development Andrew Stalker andrews@newsbase.com
Published by
A note from the Editor
t en em pl p su
The theories behind the sinking of nine tendons and what they mean for deepwater production
Recruitment 40 Contacts 41 NEWSBASE
August 2015
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A note from the Editor After some delays and much speculation, midJuly saw the UN P5+1 group agree to the deal which – in time – is likely to lead to the relaxing of sanctions on Iran. The move is as historic for global politics as it is for the oil and gas industry, and could hold a new wealth of potential opportunities for service and technology providers. Having been largely excluded from capital markets and access to equipment, both Western and Eastern companies have much-needed technology and expertise to bring to the country, from up- to downstream. Many firms, especially Asian and European, are likely eyeing up their prospects already. Taking a wider look at global inventors, we also investigate Thomson Reuters’ 2015 “State of Innovation” report, which profiles the companies and trends behind the global oil and gas patent filings. Sinopec leads the pack with 1,946 patent inventions filed in 2014, in a list which includes some of the biggest and brightest industry innovators. Seismic technology, despite its importance, is often overlooked as an area with the potential to drive radical changes. But one Californian start-up believes its new Distributed Seismic Source™ technology could change the economics, accuracy and environmental impact of marine and downhole surveys. GPUSA president James Andersen explains the story behind his innovation overleaf. We also explore some of
the technology on offer from pioneering subsea innovator Teledyne Marine Systems – seen on this month’s cover. Our special focus for this month is the upcoming SPE Offshore Europe, held 8-11 September 2015 at the AECC, Aberdeen. As well as the latest offerings from a spectrum of exhibitors, we also hear from the conference’s keynote chairman, Michael Engell-Jensen, and technical chairman, Charles Woodburn, about how technology can be a driver for efficiency, safety and cost savings. Aberdeen-based Kongsberg Maritime highlights some of the features behind its integrated control and safety system (ICSS), the exciting new projects in which it is being deployed, and how it provides clients with “The Full Picture.” We also give you an overview of the engineers and contractors taking part in Statoil’s mammoth Johan Sverdrup project. Meanwhile, IMG Composites’ Ian Taylor discusses the poor reputation of composite “wraps,” and how the company’s composite repairs are being executed to a higher standard. As well as a look at the peculiar setbacks affecting Chevron’s Big Foot setback, the increasing capabilities of robotics for inspection and maintenance, we also feature our regular recruitment section, complete with the latest international industry job offerings. All of us here at InnovOil would like to wish you a happy and productive August, and we very much hope to see you at Offshore Europe in September.
Andrew Dykes Editor
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InnovOil
August 2015
Distributed Seismic Source™ – the new gun in town? GPUSA President Jim Andersen explains how the company’s Distributed Seismic Source™ for marine and downhole applications shatters conventional wisdom
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ecent events have highlighted the oil industry’s need for improved seismic sources. In March 2015, 75 leading ocean scientists from the US and around the world sent a letter to US President Obama urging him to reconsider his approval of a planned oil and gas exploration programme using seismic air guns off the US Atlantic coast, exploring deepwater offshore potential from Delaware to Florida. They claim that the harm from seismic blasting will be significant and long-lasting for large populations of marine life. As NRDC Marine Mammal Protection Project director Michael Jasny commented: “Seismic blasting is likely to have a terrible impact on Atlantic sea life before the first well is even drilled.” Replacing such impulsive air gun sources with controlled marine vibratory sources could greatly reduce the harm to marine life, while new – and perhaps less harmful – techniques could improve the survey results. Lower oil prices are also forcing the industry to find and implement new ways to realign their production costs to match the new oil price reality. Many companies are investigating ways to squeeze more out of existing wells rather than drilling new ones. Additionally, while the US’ shale boom may be slowing, the potential of refrac operations is beginning to be explored, where better seismic imaging will be crucial to maximising new production from older wells.
The MV-12 contains a 3 horsepower motor which drives the transducer from 0-100Hz at sweep rates from 2 to 30 seconds
Good vibrations A solution to these demands is offered by an innovative California start-up. GPUSA has developed a new type of seismic source that it claims is so powerful that it could fundamentally change the way exploratory seismic surveys for oil and gas are
performed. Its patent-pending Distributed Seismic Source™ (DSS) technology holds promise for operators across the world, with the potential to lower costs, provide better seismic images and ultimately better results. A seismic source generates controlled seismic energy used to perform both reflection and refraction surveys. But knowing the limitations of existing source technology, GPUSA’s design engineers began the process from a clean sheet of paper. DSS uses state-of-the-art factory automation and programmable logic technology to precisely control small, rugged, yet very powerful, motors. These produce vibrations and sound far beyond the capabilities of traditional piezoelectric devices, while minimising the unnecessary out-of-band signals that can potentially harm marine life. In addition, putting both the seismic sources and the receivers closer to the reservoir can also result in better, higher resolution images for more informed decision making. DSS downhole sources allow this to be done at lower costs and far more practically than competing solutions. It also features a simple user interface. The DSS’ control system is based on Lenze Americas’ latest programmable logic, variable frequency drive electronics, and is completely controlled via touch screen – or even remotely via an internet connection. The unit also includes external connections for synchronisation pulses, time stamps, contact closure and more. Lowering the guns Over the past few decades oilfield seismic technology has seen tremendous advances. Progress has seen the industry transition from 2-D surveys in the 1970s, to 3-D
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Each downhole source module contains an integral 2.5-HP motor, unbalanced mass, and monitoring accelerometer
surveys in the early 90s and more recently to 4-D surveys, enabling operators to see reservoir changes over time. But the majority of these advancements have been driven by advances in sensors – the move from analogue to digital to fibre, for example – and processing power, owing to the even more rapid advances in computing power and speed. Comparatively, through this period, seismic source technology has changed very little. For decades, the primary nonimpulsive land seismic sources have been seismic vibrators (vibroseis) for surface and piezo vibrators for downhole, while marine surveys have primarily used air guns. GPUSA’s president, Jim Andersen, has been involved in sonar, acoustics and seismic technology for over 30 years. Indeed, as a nuclear submarine officer in the 1980s, he developed a great appreciation for acoustic sensors, as they were the only “eyes and ears” he could rely on when piloting submarines. Later, Andersen led the teams that developed the first fibre optic sensor systems for both US Navy sonar and oilfield seismic applications. Whereas piezoelectric technology is well-suited for high- and midfrequency applications, Andersen believes that scaling these technologies to produce the lower frequencies needed for seismic (i.e., 100 Hz and lower) is very difficult, if not impractical. Marine vibrator Compared to other offshore oil and gas activities, seismic exploration using air guns
produces some of the loudest sounds. The sound spectrum output from an air gun produces frequencies that are useful for seismic exploration, but also extraneous frequencies which are not. “Useful” sound is typically in the range of 100 Hz and below, while any output above this is usually ignored for data collection purposes. Many sea animals also have hearing that is focused primarily in the higher frequency range, and it is therefore proposed that limiting the output of such seismic signals to 100 Hz or less could reduce the impact on such animals dramatically – without affecting the quality of the seismic data. Marine vibrators use low-frequency vibration to generate seismic signals, without the “blast” of the air gun method. The current leading technical approach for marine vibrators relies on variants of the flextensional transducer, originally developed in the 1980s for US Navy lowfrequency sonar applications. This method uses a ceramic stack inside an oval elastic shell which oscillates under high applied voltages, producing energy which is put into the water and fed to receivers. Because they rely on piezo materials as their driving force, they are traditionally complex, heavy –typical systems are around the size and weight of a car – and expensive. GPUSA’s patent-pending method is fundamentally different, an approach which Andersen calls “elegantly simple.” Low-frequency transducers must displace relatively large volumes of water to achieve high power levels. But GPUSA’s MV-12 marine vibrator precisely controls NEWSBASE
powerful, 3-HP motors to achieve water displacement many times higher than is possible with piezo devices. In contrast, it also about the size of a car tire and weighs just over 100 lbs (45 kg). The DSS is designed to generate a sound pressure level (SPL) of over 210 dB that is reproducible and linear, without the seismically useless but harmful impulsive high-frequency signals. As InnovOil went to press, testing of the MV-12 was under way at a US Navycertified sonar calibration facility. Pending the final results, Andersen was confident that the 12-inch (305-mm) diameter marine vibrator would generate a confirmed SPL at 210-dB levels and frequency of 100 Hz. Even at conservative estimates, this is up to 100 times higher than traditional marine vibrator designs. Downhole vibrator The GPUSA downhole vibrator source is based upon orbital vibrator technology that is small, inexpensive, yet extremely powerful. It provides approximately 2,500 pounds-force – up to 50 times more powerful than other downhole vibratory seismic sources. Impulse sources such as sparkers, air guns and explosives concentrate most of their energy over a very small time interval – of the order of milliseconds. As a result, their results are typically non-linear, not reproducible, and potentially destructive when used in a wellbore. By contrast, the DSS distributes its energy over an extended period – typically 5
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Right: IP65 Enclosure provides protection from dust, oil and water wash down. Electronics meets UL-508C standards for Industrial Control Equipment. The system is completely controlled via an easy to use touch screen and can also be controlled remotely via the Internet.
seconds or longer, though the unit features an adjustable sweep of 2 to 30 seconds – similar to a vibroseis source. Non-impulsive or distributed energy downhole sources can quadruple the spatial/temporal resolution, based upon a fourfold increase in received frequency (from 50 Hz to 200 Hz). Data can also be stacked multiple times through repeatable surveys to produce a much clearer picture. Placing these powerful sources beneath the near-surface weathering layer can eliminate 95% or more of the attenuation seen by surface sources, effectively providing the downhole equivalent of a 50,000 poundforce surface source. Up to ten Distributed high power sources can also be placed on a single downhole cable. The implications of GPUSA’s technology are wide-ranging. DSS can enable cost-effective, high-resolution subsurface imaging to enhance recovery from conventional oilfields, aiding steam, water and CO2 injection; heavy oil, including steam chamber growth, and steam breakthrough prediction; shale oil and gas production, as well as providing permanent monitoring for carbon capture and storage (CCS). The economics of DSS are also persuasive. A single-level system works out at around the same cost as two days’ worth of vibroseis truck rental, dramatically lowering the price-tag of both individual surveys and continuous 4-D seismic monitoring. At around one-tenth the size and weight of the competition, it is also much easier to deploy. The DSS combines over 30 years of proven industrial vibrator technology with the latest oilfield downhole deployment knowledge, cutting-edge automation and programmable logic technology. The result is, Andersen says, “the world’s most powerful, rugged and reliable downhole oilfield source.” n Contact: Jim Andersen, President & CEO Email: sales@gpusa-ca.com Web: www.gpusa-ca.com NEWSBASE
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Offshore Europe Special supplement Pages 9-25
Keynote speakers
Charles Woodburn & Michael Engell-Jensen Pages 10 & 20
Safety and control
Love low logistics
ICSS from Kongsberg Maritime
Solutions from Teledyne Marine Systems
Page 16
Big deals
Page 12
The contracts behind Johan Sverdrup Page 24
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InnovOil
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August 2015
Offshore technology: The next generation Offshore Europe 2015
Charles Woodburn, technical chairman of SPE Offshore Europe 2015 and Expro CEO, discusses the future of industry technology and skills
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harles Woodburn has been Expro’s Chief Executive Officer since September 2010, following 15 years with Schlumberger where he held several senior management roles, including President of Wireline and Vice President of Engineering, Manufacturing and Sustaining. He holds a PhD in Engineering from Cambridge University. As technical chairman of SPE Offshore Europe 2015, he is also overseeing the technical papers being presented at this year’s conference, under the key theme of “How to Inspire the Next Generation.”
Q
The past year has been a fairly turbulent one for the industry – what effects do you think it has had on innovation and technology?
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The dramatic fall in the oil price during the past year had a major and immediate effect on our customers, the oil and gas operating companies, and we have all adjusted our priorities accordingly with an increased focus on costs. While cost always has been on our agenda, and always will be, it has moved right up the priority list. We can achieve cost savings through industry collaboration, standardisation and designing fit-for-purpose rather than over-engineered solutions. While there is absolutely no compromise to be made on safety, we need to get the balance right with respect to our other priorities. Speaking from the service company perspective, if we can be innovative to help keep our customer projects viable against their economic thresholds, then their success is good for us too. This might involve multi-skilling our workforce, being more responsive, introducing new costsaving technologies or simply doing more for less. We do our best to be constructive in collaborating with clients who are all currently looking at ways of cutting costs.
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As Technical Committee Chairman, what currently excites you in terms of new oil and gas innovations?
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Having been involved with this business for 20 years, I have observed first-hand the tremendous capability our industry has to invent and reinvent, particularly in challenging times such as we face today. A case in point is the improvement in our ability to produce the unconventional resources from tight oil and gas reservoirs in the United States. During the evolution of this business in a relatively short space of time, there are multiple lessons learnt which could be applied more broadly across the global industry. Standardisation and efficiency, the so-called factory approach to operations, have made these fields viable despite their very marginal economics. Another area where I expect to see more progress is cost-effective, life-of-field subsea well intervention. There is currently a large gap in the market for this technology. As the number of deeper water developments, and thus subsea wells, increases, it will become ever more important to improve recovery from these wells to ensure long-term project viability. If we could run measurements and interventions over the life of a subsea well, we could improve ultimate recovery – and thus improve field economics. We need this more now than ever.
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What should be the greatest priority for the European offshore industry at the moment?
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Our top priority is to make a strong case among the people of Europe for a more balanced debate about meeting energy demand while balancing concerns over climate change, security of supply and consumer affordability. Oil and gas will remain indispensable to the world for providing heat, light, transportation and prosperity for many decades yet. According NEWSBASE
to the International Energy Agency’s World Energy Outlook 2014, oil and gas will still supply around half of the world’s energy demand by 2040. As part of this debate, the general public has some difficult choices to make with regard to living standards, the costs of energy and the health of the overall economy – all of which would be challenged without the strong contribution made by our industry. We often don’t do ourselves full justice in terms of setting out our vital role in meeting the expected long-term demand, and other more vocal parties end up driving the debate. It is very important that our industry explains how it can deliver society’s energy needs in a safe and environmentally responsible manner. And we all have a role to play in this: operators, service companies, and industry groups and associations.
Q
SPE Offshore Europe 2015 features a dedicated Deepwater Zone. What equipment is having the greatest effect on this sector in particular – and where is more work needed?
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The subsea revolution will continue throughout industry ups and downs, as deepwater projects are critical in terms of production to meet the long-term energy demands I have already mentioned. This means that technology will increasingly be driven to the seabed. We need to replicate all the processes available at the surface such as fluid processing and reinjection. But there are serious technological challenges involved in terms of automation, control and safety, and we still have a long way to go. As more and increasingly complex hardware is located on the seabed, we will also need the technology
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Offshore Europe 2015 SPE Offshore Europe 2015 will be held 8-11 September 2015 at the AECC, Aberdeen and is completely free to attend.
to service, retrofit and repair it. As this capability becomes available in the future, I see this area providing a very rich base for industry collaboration.
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What advice can you give to smaller innovators trying to attract the attention of big industry players?
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I strongly believe in the power of professional industry associations such as the Society of Petroleum Engineers (SPE), which collects, disseminates and exchanges technical exploration, development and production knowledge. In addition, events such as SPE Offshore Europe 2015 provide a platform for individuals and organisations to present innovative technical solutions and practical case studies to a global audience. With attendance made even more compelling against the current challenging industry backdrop, our event in September in Aberdeen will allow people from all parts of the industry to come together to discuss the challenges we are facing today and into the future. n
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Offshore Europe 2015
Ultra-marine technology from Teledyne Technology from Teledyne Marine Systems enables a lowlogistics, unmanned approach to offshore inspection and survey
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urvey and inspection in the offshore industry have traditionally been carried out by large ships and work-class remotely operated vehicles (ROVs), both of which have limitations and carry significant expense. Yet current market conditions make new and emerging technologies of particular interest in the offshore industry. While low-logistics unmanned vehicles are not new technology, they are emerging as the latest stars in the offshore sector and though they also have limitations, the safety and efficiency of the vehicles and the low cost of operation, when compared to traditional means, are of increasing appeal. Changes in technology Large monolithic autonomous underwater vehicles (AUVs) and work-class ROVs have been used for oil and gas applications for many years, but are expensive to operate and maintain, and their size can preclude them from operation in sensitive or confined areas. The smaller, low-logistics ROVs and modular AUVs have also been around for years but have been used primarily in research and military markets. Recent advances in technology, however, have resulted in low-logistics AUVs and ROVs that are robust, reliable, and packed with features that rival their larger counterparts, offering operators in the offshore market a greatly expanded tool kit from which to work.
Small – but high-powered Large and expensive hydraulic work-class ROV systems are a capable and vital asset for subsea construction, salvage, completion, and heavy duty intervention tasks. However, operations around subsea structures like platform jackets, spars, risers or complex manifold, processing, and gas compression plants are always challenging for work-class systems. Their sheer size can prohibit access to the entire structure to observe all surfaces or even complete other simple non-destructive testing (NDT)/ intervention tasks and their sheer mass, plus the size of the support vessels involved, can also present potential hazards when operated in proximity to high-value assets. In contrast, small ROVs have advanced in capability and are significantly changing the economics of many missions. Available in many sizes and price ranges these ROVs enable rapid and effective inspection of the seafloor and structures. Though depth ratings of most small ROVs are not typically equal to work-class ROVs, new technology has brought deeper missions within reach of smaller systems, through novel means of deployment, thus greatly improving the economics and value of ROV operations. Solutions such as the Teledyne SeaBotix Containerised Delivery System (CDS) allow for small ROVs to be employed for certain tasks which would typically require the much larger and more expensive work class system. The single-point lift CDS NEWSBASE
is designed to have a minimal shipboard footprint and is built into a standard size 20-foot (6-m) shipping container. The CDS is a turnkey solution capable of deploying its ROV system to 4,000m, beyond the operating capability of other standard observation class vehicles, and equal to that of work class ROV depths. While the smaller ROV is not capable of some of the heavy intervention tasks of the work class system they are perfectly capable of observation, survey, and light intervention missions at significantly less cost than a work class ROV spread and its associated DP vessel. Teledyne SeaBotix Containerised Delivery System An array of on-board sensors support applications such NDT, leak detection and pipeline survey, plus improved autopositioning and station-keeping, further reduce the burden on operators. While the user base is growing, the gap between the capabilities of work class ROVs and the mini-ROVs is decreasing. These low-logistics ROVs now offer the high thrust-to-weight ratio required to support long tethers in high currents. Flexible architectures allow these ROVs to be adapted to multiple imaging and survey sensors, thus a low-logistics mini-ROV can now support missions in nil visibility and high current environments. A previously slow, expensive, if not impossible task is now routine and economical.
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Offshore Europe 2015
Teledyne SeaBotix Containerised Delivery System
Additionally, work-class ROVs are often tasked to complete precise and complex operations using large manipulators and other hydraulic tooling. This combined requirement of dexterity and subtle movement often demands additional perspective for the pilot beyond that provided through onboard or manipulator wrist cameras. The presence of an additional ROV to provide the needed thirdperson perspective is often the solution– but
this can virtually double the cost and risk of the procedure. The Teledyne SeaBotix vLBV, however, can be mounted inside a garage or Tether Management System (TMS) along with a subsea level wind spooling winch for pay out and retrieval of the 200m vLBV excursion tether. This entire unit can then be mounted into a skid on the work-class host vehicle or its TMS. The unit is then interfaced through an NEWSBASE
intermediate electronics bottle for supply of 120 VAC or 28 VDC to the system and subsequent transfer of control signals and sensor data via the host ROV umbilical to the topside control room. This permits 360-degree safety cover around the workclass system and the valuable third-person perspective. Additionally, this asset can be deployed to access compact spaces around structures, jackets and subsea plant like wellheads, manifolds and BOPs.
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Offshore Europe 2015 The Gavia modules are fully independent, interchangeable and easily transportable
Modular, low-logistics AUVs Modular, low logistics autonomous underwater vehicles (AUVs) now provide a level of operational flexibility that was impossible to achieve with earlier monolithic systems. Fully modular, low-logistics AUVs with offshore survey capability were first deployed in the energy sector in the mid- to late-2000s. The Teledyne Gavia AUV is the primary example of a fully modular AUV that is truly reconfigurable by operators in the field. The Gavia is comprised of 200-mm diameter cylindrical modules, which can be dedicated to particular tasks or equipped with an array of sensors. A complete system can range from 1.85m long (weighing 60kg in air) to 3.2m (100kg), depending on the modules used. The Gavia AUV The Gavia AUV is widely used for commercial survey applications and is in use by a number of service providers including GAS Survey, NCS Survey, UTEC Survey, PT Java Offshore and Svarog of Russia. The vehicle is used commercially worldwide, and vehicles are typically employed by commercial survey firms for applications such as pipeline route survey and inspection, a variety of pre- and post construction support applications, and dredge monitoring. Gavia AUVs typically operate from
vessels of opportunity providing highquality, cost-effective survey solutions compared to dedicated survey vessels, large ROVs or tow bodies. Each of these Gavia AUVs can be changed from one role to another in the field by swapping the survey, environmental sensing, battery and navigation modules. In fact, there are examples of the commercial users renting academic payload modules to support critical mission requirements. The advantages of a fully modular AUV system include ease of deployment, ease of storage, transport to site, small deployment team and modular sensor platforms. In addition, operators have the ability to adapt the AUV capability in-theatre, and longer mission endurance is enabled by multiple swappable battery modules. Modular systems allow for fast mission turnaround, ease of maintenance, and replacement of modules without losing operational capacity. Future sensor solutions can also be integrated into a module while offline, and then added to the AUV in the field, enhancing capability. Modularity can also extend service-life by allowing users to replace individual modules when they become obsolete, or as a result of technology advances or changing capability requirements, without losing the operational AUV asset for an extended period through factory
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overhauls or reconfigurations. Full AUV modularity answers the requirement for an asset that can be designated to a variety of tasks as they arise without being dedicated to one task, while allowing future upgrade paths. Industry, service providers and operating companies must be responsive and innovative in the current oil and gas market conditions. Closer co-operation between stakeholders is a key way to ensure success with the low price of oil demanding greater flexibility and more cost-effective solutions. Low-logistics unmanned systems offer an opportunity to greatly reduce costs and health, safety and environment (HSE) risks for a growing number of commercial oil and gas tasks and will continue to evolve in capability, thus ensuring their place in the toolkit of surveyors for years to come. n Contact: Alasdair Murrie, VP Sales and Marketing, Teledyne Seabotix Phone: +1 (619) 450 4000 Email: alasdair@seabotix.com Arnar Steingrimsson, Director of Sales - Vehicles, Teledyne Gavia and Teledyne Webb Research Phone: +1 (508) 563 1000 Email: arnar.steingrimsson@teledyne.com Web: www.teledynemarine.com/
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Offshore Europe 2015 Dean Jennings, Kongsberg Maritime
KONGSBERG’s integrated controls offer The Full Picture
Ahead of SPE Offshore Europe 2015, Kongsberg Maritime explains how its integrated control and safety systems (ICSS) allow operators to control complex production facilities, using KONGSBERG’s “The Full Picture” philosophy.
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loating production, storage and offloading (FPSOs) and other production facilities are now tasked with a myriad of functions. Controlling the information, safety and complexities of various automated systems is therefore a major priority to ensure assets maintain optimal production and operation of the controlled process. Global technology firm Kongsberg Maritime is well-versed in these challenges. The company’s extensive expertise – parent company KONGSBERG celebrated its 200th anniversary last year – in dynamic positioning and navigation, marine automation, topside production F&G ESD and PSD, cargo handling, subsea survey and construction, maritime simulation and satellite positioning allows it to draw on a wealth of knowledge when designing and implementing integrated control and safety systems (ICSS). The company’s aim and approach with these systems is to maximise performance by providing what it terms “The Full Picture”. In this respect, its ICSS is based on a flexible hardware and software design solution, such that individual parts can run as stand-alone systems or can be offered as part of an integrated system
that communicates with other Kongsberg systems, ultimately ensuring stable and optimal operations/production of assets. Integrated expectations Kongsberg Maritime’s base in Aberdeen has been servicing the North Sea oil and gas industry for over 30 years, delivering systems and solutions for the control and safeguarding of oil and gas production in a modern context. The philosophy behind the KONGSBERG system is one of openness and standardisation, allowing information to be collected and displayed clearly to all users. A standardised network allows the free flow of information from sub-systems, with system-wide information available for monitoring, operation, alarming and trending on multi-functional operator workstations. This approach to control systems extends across a wide spectrum of standard, specific or bespoke functions, integrating process and utility controls, mechanical and machinery packages, power management, subsea, cargo and ballast control systems into a single common HMI package. A major additional component is the Information Management System (IMS) – information architecture for plantNEWSBASE
wide information storage and retrieval. The infrastructure comprises system components such as portal, data logging, secure network, malware protection, replication, security and integration by standard protocols. This includes global tools for personalised dashboards, alarm statistics, trend and reports, as well as control system condition monitoring. Cargo management, meanwhile, is handled by the Cargo Level System (CLS). This includes a RADAR-based CLS for oil and slop tanks, as well as sensors for cargo vapour pressure and temperature measurements. Draught, trim, list and ballast measurements are fed into load and stability calculation software which then ensures safe and stable vessel operation. Likewise, KONGSBERG’s design incorporates its own suite of safety systems, again integrating components such as fire and gas detection and response, as well as emergency and process shutdown controls. This means KONGBSERG’s ICSS provides operators with access to all the information and tools required to work safely and manage critical situations. Standards and savings From equipment rooms and individual processes through to onshore bases, the use
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Offshore Europe 2015 Offshore Production Unit
of standardised hardware also has major benefits. Not only can users work between multiple systems with greater ease, but with multiple functions applied on the same standard hardware platforms, fewer onboard spare parts are required, thus saving space and lowering costs. In addition, this makes the system easy to maintain and simple to upgrade, reducing costs through the asset’s life cycle. These benefits are magnified when the production and safety system are combined with KONGSBERG’s dynamic positioning (DP) and navigation system – the result is full-scale integrated asset management. UK Sales Manager for Offshore Production Systems Dean Jennings explained to InnovOil that “KONGSBERG’s integrated system utilises the same Remote Control Unit (RCU) and Remote I/O hardware to control the majority of our systems – from DP to process control – therefore reducing the amount of modules required to automate any facility, from fixed platforms to FPSOs.” This approach extends throughout the life of the project. “In addition,” Jennings says “The new generation of Kongsberg Control Systems will enable “plug and play” technology between legacy KONGSBERG products”.
Competence in all phases In terms of its approach to design and automation, KONGSBERG works closely with experienced users to maximise the system’s benefits. It can also draw on its wealth of expertise across the sector, using in-house tools such as an instrument/alarm database, field loop documentation, offline and online configuration tools and process mimic editor, as well as data sheets on shutdown systems and fire protection. In addition to this, Kongsberg Maritime Engineering, a wholly owned subsidiary of Kongsberg Maritime, acts as a contracting solutions partner, specialising in EIT engineering and system integration and EPC contracting. Jennings explains: “We offer a global single source solution for any size EIT contracts, both on an EPC and EPCI basis. Our multi-discipline competence enables us to provide holistic and uniform solutions that meet our customers’ requirements for operational safety and efficiency, as well as cost effectiveness.” This expertise also extends to retrofitting existing vessels. “KONGSBERG has upwards of 17,000 assets utilising our systems with many different generations of hardware/software across these assets,” NEWSBASE
Jennings says, “We are extremely well-versed at integrating systems across the product generational gap.” Indeed, this competency has led the company to develop standard products and packages to minimise the bespoke work required. “Of course we have to bespokeengineer a certain percentage to bridge the technology gap and to ensure all new regulations are met. Where possible we can also improve upon legacy systems with our current technologies,” he enthuses. Local life-cycle support Kongsberg Maritime supports customers world-wide in their efforts towards predictable, safe and un-interrupted operations throughout the lifecycle. It provides training together with world-class products and global customer support. Jennings comments: “As a manufacturer, we systematically support our customers in their efforts to build competence. We offer both standard and tailor-made courses that focus on how to operate and maintain the product.” He adds: “At our Aberdeen base, the Offshore Production team has expanded from nine to 14 engineers in the past year, and proactively supports our customers to maximise the operation and productivity of their assets”.
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August 2015
Offshore Europe 2015 ICSS Operator Station
Significant contract wins The high calibre of the firm’s ICSS solutions has led to a string of new contracts: most notably, the Statoil contract for the Mariner field in the UKCS, which involves “The Full Picture” automation delivery to both the production and living-quarters platform and floating storage unit. In addition to this, last year saw Statoil award the company a FEED and potential delivery contract for safety and automation systems (SAS) across the four platforms of its mammoth Johan Sverdrup development. The contract includes process and power distribution control, as well as process and emergency shutdown, and Sverdrup’s fire and gas safety systems. The agreement cements the two companies’ relationship, with KONGSBERG having already installed similar systems on 10 other Statoiloperated platforms. Jennings comments: “These contract wins demonstrate Kongsberg Maritime’s strong capabilities and our solid position within topside automation for offshore oil and gas production units”. Momentum behind its ICSS solutions has grown over the past year, with KONGSBERG developing ICSS
E-House and electrical systems for the BW Offshore’s Catcher FPSO. The vessel, to be deployed to Premier Oil and Cairn Energy and MOL’s Catcher field in the North Sea, will produce 60,000 barrels per day, with the capacity to store up to 650,000 barrels. KONGSBERG will supply its K-Chief 700 marine automation system for vessel control, K-PRO for process control, K-Safe for fire, gas and safety including process shutdown (PSD) and emergency shutdown (ESD), as well as a fire and gas detection system. This year, the company has won contracts to install the same systems, as well as instrument, telecom and surveillance equipment on the Yinson Production FPSO, aimed to be operational in Ghana’s Tano Basin by mid-2017. The project itself is based on a conversion of the 1996 Yinson Genesis VLCC – a prime example of the scale of retrofitting now under way to create new FPSOs. A recent agreement with ABT Oil and Gas (ABTOG) also hints at where the future of ICSS may lie. The companies’ collaboration agreement will see them jointly develop a proof of concept for “normally unattended installations” (NUIs) in marginal fields. ABTOG’s NEWSBASE
Marginal Field Initiative has been covered in InnovOil previously (see January 2014 Subsea Special), as the company aims to use unmanned and remotely operated facilities to produce from smaller or depleted fields unsuitable for full-scale developments. As part of the two-stage proof, KONGSBERG aims to prove that its existing ICSS solutions can be used to design and implement NUIs in future fields. Jennings comments that this proof of concept “will deliver considerable economic cost savings, making the development of marginal fields a significant and viable proposition.” The ABTOG project highlights the potential that KONGSBERG’s technology offers. Ultimately, the combination of KONGSBERG’s experience across positioning, communication, control, navigation, simulation and automation systems makes it one of the best-placed providers to offer “The Full Picture”. n Contact: Dean Jennings, Sales Manager, Offshore Production Systems Tel: +44 (0)1224 278 300 Email: dean.jennings@kongsberg.com Web: www.km.kongsberg.com/offshoreproduction
Saltel Industries going offshore www.saltel-industries.com
Saltel Industries is an innovative quality oriented company that develops, manufactures and operates Expandable Steel Patches and Expandable Steel Annulus Packers. Saltel Casing Patches allow restoring well integrity and optimizing the production in both mature and new wells applications. Saltel Expandable Annular Isolation Packers provide a permanent and reliable annular barrier, preventing from migrations in the annulus, for Shale Fracturing, Multistage Cementing and Cement Integrity.
Saltel Expandable Steel Patch Technology
Saltel Expandable Steel Packer Technology
As optimizing the recovery of hydrocarbon reserves has grown in importance, and effective reservoir management has become increasingly complex, the need for shutting-off unwanted perforations in both production and injection wells has been growing, and requirements to restore casing condition to lengthen well life have become common. A wide number of very different solutions have been used, including cement squeezes, injection of gels, straddle packers, and various composite and steel patches, all with varying levels of success.
The Expandable Steel Annular Isolation Packers are slid onto the completion casing, and sealed by welding or crimping. Hydraulic pressure is applied in the completion casing to expand the metallic sleeves up to the contact with the formation or casing it is set in. As a result, the stainless steel sleeves plastic deformation creates a solid and permanent annulus seal.
Saltel Industries has developed, tested and trialed the use of a stainless steel Patch which is expanded down hole to create a high pressure inner lining inside the casing. Initially designed for perforation shut-off the technology is also suitable for repairing short lengths of damaged or corroded casing. The SES Patch has proven its efficiency in terms of setting reliability, effective sealing, resistance to harsh environments and pressure resistance for a variety of applications such as: Enhanced Oil Recovery & Production Optimization: Perforations Shut-off, (Water, Gas & Sand Control) High Temperature Remedial applications (Completion Repair in CSS and SAGD wells) Well Maintenance and Repair: Parted Casing, Casing leaks, Tubing Leaks, Corrosion, Sliding Sleeves, Sealing leaking couplings, Sand Screen Repair... New Well Applications: Sealing Frac Ports, DV tools, Cement ports...
SES Packers meet the requirements of the most challenging applications, such as deep offshore completions. Qualified under ISO 14310, the Well Integrity - Annular Zonal Isolation Packers (WIAZIP) provide a permanent annulus sealing. The V0 rated expansion valve guarantees the casing integrity once the packer is set. Instrumented with electronics, it is possible to confirm that the packer is properly set. Besides, annulus pressure and temperature conditions are accessible during the whole life of well with a wireline intervention even through multiple casing layers.
Saltel Expandable Steel Packers vs Deep Offshore requirements
Cement Replacement Application with SES Packer Technology
SES Patch innovative features • • • • • • • • • • •
Expandable stainless steel Top – Down setting Real time Quality Control Maximum ID allowed Settable in casing, tubing or openhole High efficiency sealing Multi-diameter sealing Sets in ovalized casing Casing will recover its original internal differential pressure rating Patch through patch capabilities Gentle setting process with energized seals
With more than 500 patches set worldwide, Saltel Industries has set Expandable Steel Patches offshore in Siberia, West Africa, and North America. Saltel Industries are now heading for 2015 Offshore Europe.
Challenging constraints of deep and ultra-deep water context, coupled with the high cost of the related infrastructure call for ever-greater optimization of production and great care of the environment. SES technology - with its isolation Packer WI-AZIP ensuring effective sealing in oval, out of gauge or irregular boreholes, answers to these challenges. The advanced E-WI-AZIP can even give well data as Pressure, Temperature, and setting status of the packer.
www.saltel-industries.com
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Keynote speaking Offshore Europe 2015
Ahead of SPE Offshore Europe 2015, the conference’s keynote chairman, Michael Engell-Jensen talks to InnovOil about safety and innovation
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PE Offshore Europe 2015 keynote chairman, Michael EngellJensen, has more than 30 years’ experience in the upstream oil and gas industry. In his current role as the executive director of the International Association of Oil & Gas Producers (IOGP), he leads an organisation which works to promote safe, responsible and sustainable exploration and production operations. His previous positions include managing director of Maersk Oil in respectively the UK and Qatar, corporate senior vice president business development for Maersk Oil and corporate SVP Carbon and Climate. This month he spoke to InnovOil about the conference agenda, the future of technology and what must take priority for European operators.
good practices that industry can reduce the level of fatalities. IOGP’s Life Saving Rules publication was developed from the safety performance database. In addition to providing simple rules to follow and guidance to ensure better consistency and standardisation in communications, it can also function as a checklist for job briefings.
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SPE Offshore Europe 2015 features a dedicated Deepwater Zone. What technologies are having the greatest effect on this sector in particular – and where is more work needed?
Michael Engell-Jensen
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The past year has been a fairly turbulent one for the industry – what effects do you think it has had on innovation and technology?
technology. We create a forum for members to come together, in a collaborative rather than competitive spirit, to create guidelines and undertake projects to help the industry perform better. We are currently working with our members on around seven joint industry projects (JIPs).
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The dramatic fall in the oil price had an immediate impact on the industry. It means companies – our members – are cash-flow constrained and thus revisit their priorities and revise the phasing of projects. For the most part, the projects are still the right ones, so they may get deferred for a few years rather than cancelled completely. The industry is also looking at extracting more difficult reserves in ageing fields or deeper waters, for example. Technology is the only way forward. It is absolutely clear that a large part of the resources open to the industry are viable only via the application of innovation and technology – even if the pace of their application is slightly delayed due to current budget constraints. The condition of the industry drives our members’ agendas and will clearly impact IOGP. Our programme has to reflect our members’ current and future needs. We too will need to consolidate certain activities until at least 2017. That said, IOGP plays a role in fostering the application of innovation and
We’ve heard a lot about industry collaboration recently – is the industry delivering?
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I will single out IOGP’s safety performance database to show how collaboration is working to benefit the industry. For 30 years, IOGP members have shared the lessons learnt and root causes of safety incidents, leading to the development of good practices and guidelines. In 2014, 52 IOGP member companies submitted safety data from operations in 110 countries, covering 4.4 billion work hours. Our database is the only one of its kind for benchmarking industry performance; only when we have such large numbers is it possible to identify meaningful statistical trends. Collaboration is very effective and powerful when used in this way. There is still room for improvement, as there were 45 fatalities across the industry in 2014. Any fatality is one too many. It is primarily by working together to develop NEWSBASE
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In the wake of deepwater incidents in 2010, IOGP created the Global Industry Response Group (GIRG) to identify, learn from and apply the lessons of well incidents. One of three entities created to manage and implement the GIRG recommendations was the Subsea Well Response Project (SWRP). Set up in 2011, SWRP’s remit was to improve subsea well control incident intervention capabilities. It had four main objectives: to design a capping stack system with a range of equipment to allow wells to be shut in; to design a subsea incident response toolkit for the subsea injection of dispersant; to assess and implement deployment options, and to complete studies to determine the feasibility of global containment systems. As a result, four capping systems and the containment toolkit are available for international use, and SWRP is now developing offset installation equipment. This will allow the removal of debris and installation of equipment in scenarios where there is no direct vertical access to a subsea well head due to a hydrocarbon plume reaching the surface. It is scheduled for delivery in 2016.
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How does IOGP engage with technology providers?
We mainly engage indirectly with technology providers. While our JIPs are often technology-focused, and may well
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August 2015
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Offshore Europe 2015 Delegates attending SPE Offshore Europe 2013
SPE Offshore Europe 2015 will be held 8-11 September 2015 at the AECC, Aberdeen and is completely free to attend.
identify technological shortcomings, IOGP does not engage directly with technology providers to specify requirements. Our committee members do this on behalf of all our member companies as part of certain projects. By way of example, one post-Macondo finding from the US Coast Guard was the need to improve its processes by providing all spill response personnel with a Common Operating Picture (COP). A COP is a computing platform that provides a single source of dynamic data and information to support emergency personnel responding to an incident. IOGP’s Geomatics Committee, on behalf of the Oil Spill Response JIP, played a lead role in responding to this finding, by developing an industry recommended practice. In doing so, our Committee interfaced closely with a number of IT technology providers who responded to an invitation to provide input to the project. Representatives from oil companies, vendors, standards bodies and regulators then reviewed these findings to decide next steps.
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What should be the greatest priorities for the European offshore industry at the moment?
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From an industry perspective, the priority is to meet the challenge of profitable extraction from the North Sea and adjacent areas. At a higher level, there is now a consensus between governments, regulators and operators that recovery should remain as high as possible for the benefit of all. This may require that revenues are split in a different way than in the past. Access to infrastructure such as pipelines is another area that may require attention, in order to encourage new developments. Safety must also remain a top priority for the industry. We must never forget that there is absolutely no economy to be made in saving on safety, even in the short term. Last month we were at a meeting in China, a country which is taking impressive steps to heighten its safety and environmental performance requirements. NEWSBASE
From an IOGP perspective, another current focus is to help get the message across that oil and gas will remain indispensable to the world for securing heat, light, mobility and prosperity for many decades to come. We acknowledge the need to reduce carbon emissions, which is one of society’s major concerns with our industry. It makes no sense that many European countries favour coal rather than gas for power generation. While coal is cheaper and therefore leaves spend for subsidising renewable developments, the burning of coal to produce electricity creates twice as much carbon dioxide as using gas. Gas is the ideal companion to renewable energy as you can turn down a gas turbine with no loss of efficiency – the same cannot be said of coal. Furthermore, gas is an abundant hydrocarbon and is so much more effective than electricity for heating. It can also be compressed, even liquefied, for transportation applications. n
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Offshore Europe 2015
Beyond “Wraps” IMG Composites’ Ian Taylor discusses the problem with composite “wraps”
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ll personnel responsible for asset integrity on Oil and Gas plant need to know something which, as a composite repair supplier, it is difficult to admit. Wraps are bad news. There is no denying that composite repairs, which have received most recognition in the form of composite pipe repairs, have a chequered reputation. In the late 1990s the early application of composite Fibre Reinforced Polymer (FRP) materials to degraded pipes was so innovative that the benefits often blinded both suppliers and operators to the potential problems. Back then, utilising any composite repair that offered the capability to protect against corrosion and reinforce a weakened substrate seemed like a nobrainer. Yet it did not take long before a need for standards emerged.
In the mid-2000s a core of composite repair suppliers and oil and gas operators worked together on a joint industry project (JIP) to set out the comprehensive ISO/TS 24817 Standard. This standard ensures that the problematic areas of engineered composite repairs are managed to a suitable degree, for both suppliers and operators. Adherence to this standard is vital to ensure a reliable repair, but too often the standard is either ignored or liberally interpreted by those who see engineering standardisation as a hindrance to carrying out repairs. The philosophy of the ISO/TS 24817 is conservatism and quality, with the aim being a safe and functional repair. All CompoSol® repairs, be they pipe repairs or structural repairs, hold this spirit at the core of their development and implementation. Substandard composite repairs give NEWSBASE
the technology a bad name. The term “Wraps” has become synonymous with this type of repair and the low expectations that come with it are counterproductive to the enormous benefit which a properly engineered and applied composite reinforcement can offer. A good reputation for composite repairs is in all suppliers’ interests, and IMG Composites is always happy to advise on the standards of quality required – no matter who they are working with. For advice and a pocketbook on best practice contact IMG Composites at the details below. n Contact:
Ian Taylor, Commercial Manager Tel: +44 (0) 1224 879 966 Email: ian.taylor@imgcomposites.com Web: www.imgcomposites.com
InnovOil
August 2015
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InnovOil
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August 2015
Offshore Europe 2015
Johan Sverdrup contracts explained 8
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Tim Skelton explores the contracts behind Statoil’s Johan Sverdrup megaproject
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ogether with project partners Lundin, Petoro, det norske and Maersk Oil, licence operator Statoil has commenced work on the massive Johan Sverdrup development. The field, located in the North Sea west of Stavanger, is estimated to contain recoverable reserves of 1.4 to 2.4 billion barrels of oil equivalent, and production should start in late 2019. Phase 1 of its development involves establishing a field centre, comprising four bridge-linked platforms for accommodation, processing, drilling and a riser platform, along with three subsea water injection templates. Contracts for the accommodation and process platform jackets are still to be awarded, but many others are already in place. Total investment now sits at around 117 billion kroner (US$14.66 billion). So who is doing what?
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Well template: Heerema Marine Contractors Contract value: unspecified Specs: 246-tonne well template. Currently being built at the VDS yard in Vlissingen, the Netherlands, it will be installed later this year.
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Riser and drilling platform jackets: Kværner Verdal Contract value: US$251 million (riser); US$130 million (drilling) Specs: Steel jackets – the tower support structures – for the riser and drilling platforms, described by Statoil as the two largest and most demanding at the development. The 26,500 tonne riser jacket will be Europe’s biggest, and is scheduled for delivery in summer 2017, with the drilling jacket set to follow in spring 2018.
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Process and riser platform topsides (fabrication): Samsung Heavy Industries Contract value: US$877 million Specs: Fabrication contract for the process and riser platform decks, to be built at Samsung’s shipyard in South Korea. The processing platform will ensure oil stabilisation, and processing into rich gas. The riser platform will deal with oil and gas exports, water and gas injection, and any future tie-ins.
NEWSBASE
Process and riser platform topsides (engineering and equipment): Aker Solutions Contract value: US$564 million Specs: Engineering work and equipment procurement management packages for the process and riser platform decks, plus hook-up work and gangways for the entire field centre.
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Accommodation platform topside: Kvaerner/KBR Contract value: US$839 million Specs: Kvaerner, in a 51/49% joint venture with KBR, will provide the complete engineering, procurement and construction (EPC) package for the accommodation platform topside, including utility and living quarters. Engineering will take place in Leatherhead, in the UK. Procurement activities will be undertaken in Norway and the UK. Manufacturing is expected to start in spring 2016, with delivery scheduled for early 2019.
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Drilling platform topside: Aibel Contract value: US$1 billion Specs: Complete EPC package for the drilling platform deck, to be constructed in three modules. The largest, the main support frame, will be built at Aibel’s yard in Thailand. The drilling support module will be built in Haugesund in Norway, and the drilling equipment set will be made by Aibel’s partner Nymo in Grimstad, Norway. All three modules will be combined in Haugesund, with completion expected in 2018.
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Offshore Europe 2015
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Power supply: ABB Contract value: US$138 million Specs: Providing land-based power to all platforms. ABB will install an onshore converter station at Haugsneset, which will transform alternating current (AC) grid power into high-voltage direct current (DC) for transmission to the riser platform, via a 200-km subsea cable. A power module on the platform will transform the power and re-convert it to AC. “Using onshore electricity [eliminates] the need for local gas-turbine power generation, significantly lowering CO2 emissions as well as operating and maintenance costs,” noted ABB’s president of process automation division, Peter Terwiesch. The equipment will be delivered during the first half of 2017.
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Pipeline: Gassco Contract value: not applicable Specs: Gassco will run the 156-km onshore pipeline, taking over as operator for the gas transport system from the field when it becomes operational. Running from the riser platform, the 18-inch (456-mm) pipeline will be tied into the Statpipe rich gas system on the seabed west of Karmøy, allowing gas to flow to the Kårstø processing plant near Stavanger.
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Drilling services: Odfjell Drilling Contracts value: US$313 million and US$232 million Specs: Two separate drilling contracts. The first is for a 3-year charter of Odfjell’s Deepsea Atlantic rig, to drill at least 13 pilot wells. The second is for drilling services on the development’s fixed drilling unit, starting December 2018.
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l Onshore support services: Baker Hughes Contract value: US$187 million Specs: Oil services company Baker Hughes will provide onshore field support services. The contract runs for six years, and includes four-year options for the life of field.
l Fire pumps: Alfa Laval Contract value: US$25 million Specs: Delivery of Alfa Laval’s Framo fire-water pumping systems to all four platforms. Delivery is scheduled for 2016.
Platform installation: Allseas Contract value: unspecified Specs: Dutch contractor Allseas will lift the platform topsides into place in single lifts using its 382m long, 124m wide mega-vessel Pioneering Spirit. The ship’s lift capability is 48,000 tonnes for topsides and 25,000 tonnes for jackets.
Other services, equiptment and analysis l Other engineering services: IKM Ocean Design Contract value: unspecified Specs: Detail engineering and services for subsea umbilicals, risers and flowlines (SURF). The 2-year contract requires IKM to complete detailed design and to follow on and supervise all pipelines and cables in the field. Phase 1 includes umbilicals and water injection pipelines running from the platforms to the injection templates to provide pressure support. l Production chemicals and services: Clariant Oil Services Scandinavia Contract value: unspecified Specs: Clariant will supply production chemicals and services. The contract has a length of eight years with a four-year option, totalling 12 years.
l Lighting: Glamox Contract value: unspecified Specs: Among its more innovative features, Johan Sverdrup will be the first offshore field development to be fully lit by LED technology. This will offer several operational benefits, including reduced maintenance, long lifetimes, lower energy use and costs, and improved environmental performance. Glamox will supply the complete lighting package, including LED light fixtures and floodlight fixtures for both hazardous and safe areas. It will also supply LED products for the accommodation platform. l Engineering analysis: 2H Offshore Contract value: unspecified Specs: Tieback conductor, platform conductor and surface riser engineering analysis.
l Safety equipment: Kongsberg Maritime Contract value: US$25 million Specs: safety and automation system (SAS), life cycle simulator, and SAS information management system for all four platforms. The order contains extensive hardware, software and system engineering competence delivery. Kongsberg Maritime will also participate with integrated engineering services to various contractors, and will support installation and commissioning of the systems.
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l Elevators: Heis-Tek Contract value: US$18.5 million Specs: Heis-Tek, the Norwegian operation of Alimak, will deliver industrial traction elevators to all four platforms during 2016 and 2017.
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August 2015
COMMENTARY
Robotics autonomous Jeremy Bowden investigates how advances in automation and robotics
are changing the way the industry looks at maintenance and inspection
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ecent advances in automated technologies hold profound implications for oil and gas operators. Maintenance and inspection techniques in particular have come on in leaps and bounds, as remote operation and substantial new computing power are applied to the offshore sector. Investment has been driven not only by the productivity and efficiency gains, but also by a reduction in the need for workers to operate in dangerous areas, enabling
companies to avoid injuries and improve their HSE performance. Robotic maintenance and inspection includes remote subsea operations and systems for topside use, ranging from tailormade solutions to commercially available inspection systems. Offshore rig-based robotic inspection typically involves remote controlled crawlers that use magnetic wheels, many of which have been profiled in previous editions of InnovOil. These vehicles are able to climb the walls and even
survey the roofs of complex structures and assets, while aerial drones and unmanned aerial vehicles (UAVs) are tackling hardto-access areas previously tasked to roped workers. The majority of these robotic systems use inspection technologies including camera systems, sensors for thickness gauging, and magnetic or electromagnetic systems. OTIS, developed by A.Hak, is a prime example of such technology, as well as the MagneBike and FAST, the latter developed by Alstom Inspection Robotics. Remote monitoring robotic systems include Carnegie Mellon University’s Sensabot, also supported by supermajor Royal Dutch Shell. Learning the ropes Among the most important innovations in the sector is Fraunhofer’s suite of inspection robots, developed at Germany’s Fraunhofer Institute. This particular unit can be taught inspection tasks using a manually operated control device. Once instructed, the robot can autonomously execute inspection tasks. This enables operators to adapt operations to each unique environment, speeding up the maintenance process while reducing costs. Yet at present, the robot is unable to deal independently with an unexpected situation, so operators can also monitor and adjust activity remotely as inspection and maintenance are carried out. To find its way around, the robot uses a laser scanner to identify specifically shaped objects such as pipes and poles, as well as stripes of reflective tape applied to the environment. A six-axis light-weight arm installed on the robot carries a camera to perform visual inspections. The robot platform has various application-specific sensors, such as a stereo microphone as well as gas and fire sensors. Wireless LAN and Bluetooth are deployed to enable the robot to communicate with the central control PC and with a mobile operator control device. The robot can navigate offshore environments safely, which enables it autonomously to record sensor data at key locations or continuously monitor
Snake arms developed by OC Robotics
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COMMENTARY FAST, developed by Alstom Inspection Robotics
sensor data along a predetermined path, supervised in real time. For non-routine tasks the user can drive the robot around the oil and gas platform in order to get close to objects that need to be inspected or manipulated. Once the user has identified an object, the robot can then automatically perform planned tasks such as executing movements, positioning its camera in front of a gauge or turning a hand wheel. Robotic manipulation systems are typically based on an articulated design where there are multiple joints that can move the robot within a given workspace. A number of different types of manipulationbased systems are used – the snake arm robot for example, by OC Robotics, is a slender hyper-redundant manipulator, with a high degree of freedom which allows highly flexible positioning of its tools. Bolt action Elsewhere, the development of more targeted automated maintenance devices is also under way. One such innovation focuses
on the single task of bolt maintenance, and has recently been acclaimed as the world’s first “independent bolted joint integrity calculation engine”. The product, known as Asset 55, has been developed in northeast England by bolted joint specialist and technical director, Robert Noble. Validated by two global independent authorities on bolted joint integrity, Asset 55 is the first independent calculator of its kind and was developed to increase safety by eliminating the risk of leaks and lengthening the life cycle of joints. Noble says it is the first product to provide independent assurance of bolted joint integrity, by considering the stress, materials and service conditions of every joint, to assess and evaluate both long- and shortterm integrity issues. On this basis he claims that the product and software upon which it is based is set to revolutionise integrity assurance. “Over the past 15 years the importance of how bolted joints are managed and maintained has increased rapidly, with NEWSBASE
the UK leading the way in oil and gas safety,” he said. “With a typical production platform featuring between 10,000 and 25,000 bolted joints, even the smallest leak can result in the closure of the site and in a worst case scenario lead to fire, natural disaster or even loss of life. Therefore ensuring the integrity of every joint is critical.” Noble also highlights the importance of the software behind the product, which is reflected by the inclusion of leading technical experts in the Asset 55 senior management team. To ensure its capability the system is regularly updated with the latest standards wherever it is in the world, and if it works offline it is updated with an overnight online check to verify calculations. “Asset 55 companies across the world are able to benefit from a truly independent solution that is continuously being updated and verified online to utilise the latest industry standards and materials. This ensures all calculations and advice is based on today’s best practice.”
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WHOI’s hybrid ROV (HROV) Nereus
Such automated maintenance devices work alongside extensive remote monitoring of more substantial rig components. Some monitoring systems, such as Automated Rig Technologies’ RPDAS (Remote Predictive Diagnostic Analysis System), can predict top drive hydraulic failures weeks in advance. Once a motor fails it ends up as scrap; this system enables a worn out hydraulic motor to be removed from service before a failure occurs, rebuilt and put back into service. Companies can therefore maximise up-time and help co-ordinate logistics, all adding to the savings that can be made. Loosening the tether Automated maintenance is particularly effective beneath the waves, where operating environments are either inaccessible or particularly dangerous for humans. Recent developments include an underwater vehicle that can switch between remotely operated vehicle (ROV) and autonomous underwater
vehicle (AUV) operations. The system has been developed by the Woods Hole Oceanographic Institution (WHOI), based on technology originally developed for ocean research and military use. This could aid the oil and gas industry by enabling a wider range of robotic interventions and maintenance for subsea infrastructure on the ocean floor. Based in Cape Cod, New England, WHOI is eager to partner with the oil and gas industry to insert this equipment into oil and gas operations. The technology behind the product brings together acoustic and optical wireless communication systems, enabling a new class of undersea vehicles to fill the void between current AUV and ROV technology. The advances are based on breakthroughs in autonomy and optoacoustic “wireless” underwater operations and micro-tether technology, developed for use in WHOI’s hybrid ROV (HROV) Nereus and other vehicles. NEWSBASE
“Removing a dependence on traditional tethers reduces the footprint of the vehicle system, meaning deepwater operations are possible from less costly platforms. Such vehicles are also adaptable for more advanced applications such as fulltime residence within a complex offshore structure; available for imitate deployment and intervention when needed,” said WHOI principal engineer Andy Bowen. With the offshore oil and gas industry venturing into deeper, harsher and more remote waters, these robotic techniques will have an ever more important role to play in offshore and subsea inspection and maintenance. Above all, there is a clear incentive for oil and gas companies to cut costs, extend equipment life and reduce the exposure of their workers to high-risk operations. With advances in both computing power and the complexities of machinery, robotic maintenance is forging a new path to achieve all three goals. n
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InnovOil
page 30
August 2015
COMMENTARY
Industry innovation made patently clear Following the publication of Thomson Reuters’ “State of Innovation” report, David Flanagan looks at the trends driving new oil and gas patents and how lower prices may affect them
F
or the last five years, media and research group Thomson Reuters has produced a wide-ranging and in-depth survey entitled the “State of Innovation” report. Its IP & Science division tracks patent filings by sector in the previous calendar year – including those filed by oil and gas firms – producing a league table for companies in each industry. The recently released 2015 report suggests that rates of innovation in the oil and gas sector remained buoyant in 2014. The top 5 innovators in established and mature oil markets such as Europe and the Middle East were JSC Tatneft of Russia, Shell Oil Company of the Netherlands, IFP Energy Nouvelles of France, Saudi Aramco of Saudi Arabia and Germany’s BASF. US rankings show a run-down of the industry’s biggest explorers and service providers, with Halliburton Energy Services in the top spot, followed by Schlumberger, Baker Hughes, ExxonMobil and UOP. Asia saw Chinese giants triumph in the form of places taken by Sinopec, PetroChina, China National Offshore Oil Corp. (CNOOC) as well as two academic bodies, University of China Petroleum and University of South West Petroleum. In terms of hard numbers, Chinese firms also remained in pole position. The global
patent figures ranked as follows: Sinopec with 1,946 inventions, PetroChina with 1,520, Halliburton with 783, Schlumberger at 448 and CNOOC with 384. Trends can also be seen between the industry’s sub-sectors. Forming 63% of all oil and gas filings, E&P activities – comprising, drilling production and processing – are still at the forefront of industry efforts. But while both upstream E&P and refining patent filings grew by 1% and 3% respectively between 2013 and 2014, gas transport fell by 1%. Making the switch Thomson Reuters IP & Science senior patent analyst Bob Stembridge spoke to InnovOil about the nature of innovations in the oil industry which he has seen over the period of its analysis. “The switch from vertical to horizontal drilling is resulting in far greater oil yields than ever. The technology enabling that switch is advancing rapidly, underpinned by a fivefold increase in innovation from around 500 patented inventions in 2000 to just short of 2,500 last year,” he explained. One example he draws attention to is patent W0201313187885A1 from Halliburton, almost certainly the result of the US shale boom. The Derwent World Patents Index (DWPI) title is a modular
Oil & Gas Overview
3%
Source: Thomson Reuters
Subsectors
1%
2014 2013 % Vol Vol Change
63% Petroleum & Gas Exploration, Drilling, Production and Processing 15,589 15,480
34%
4% Petroleum & Gas Fuels 3 and Other Products 63%
+1%
8,459
8,464
0%
3% Petroleum & Gas Transportation and Storage
658
664
-1%
1% Petroleum Refining
183
178
3%
actuator for use in rotary steerable drilling systems for directing drill strings for drilling boreholes. It has a control system regulating the movement of actuator pistons between two positions, such that the piston enables changes in the direction of the string. China’s state-owned Sinopec meanwhile, appears to have maintained a focus on downstream innovation, likely the result of growing demand for transport fuel. Its work has included “crude oil fractionation and cracking to produce heavy oil/ diesel fractions…as well as synthesis of petrochemicals such as polymers, aromatic compounds, alcohols, aldehydes and acids.” Upstream innovation would seem to have been tasked to PetroChina, whose recent patents have included methods for “discovery, exploration, drilling, extraction, well-head processing and pipeline technologies.” The group expects these regional and corporate trends to continue, especially with the evolution of the hydraulic fracturing industry, and for which China and Russia in particular will be keen to innovate. It sees a continuation of methods supporting the switch from vertical to horizontal drilling, including fracturation techniques. Supporting this, downhole seismology data streaming is likely to see more attention, as operators look to achieve even greater Oil Price vs Number of Innovations 300 250 200 150 100 50 0
2000
NEWSBASE
Crude Oil Price $US/bbl Oil & Gas inventions (100’s) Upstream (100’s) Downstream (100’s)
2014
August 2015
InnovOil
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COMMENTARY
accuracies and efficiencies. At present, data stream rates are poor, and much faster rates are required for better understanding a formation’s geology. Furthermore, some fossil fuel companies are also placing a new focus on renewable energy, suggesting new technologies may well be developed in the next few years as a result of this desire to diversify. Price pressures Looking ahead, many providers and innovators are questioning how the current fall in oil prices will affect technology development. Thomson Reuters’ research noted that a dip in the oil price during 2009 was followed by a slow-down in growth rates of innovation in 2010/2011. The recovery of prices between 2009-2012 was followed by an increased rate of innovation in 20112013, while the following dip between 20122013 correlated to another slight slow-down in 2013/2014. Interpreting the research, Stembridge told InnovOil: “Broadly speaking, the oil price has risen over time and so has innovation, as measured by inventions described in patents both in oil & gas generally, and in both upstream and downstream technologies.” Yet while there is some evidence of a correlation between price and the intensity of innovation, Thomson Reuters considers the link to be relatively tenuous. “It looks like there may be a tendency for the innovation trend to track the oil price with a delay on average of around 18 months, although the correlation looks pretty weak,” said Stembridge. Given current market trends, the relevance to innovation of trends in oil prices may now become the subject of increased debate. Over the long term, the general conclusion to be drawn is that, across upstream and downstream, as oil prices have risen, so too has the rate of innovation. It is
likely that higher oil prices have translated into higher budgets available for research and development, which naturally lead to fresh innovations – and the greater the revenues from operations, the more easily is the industry able to bear higher costs. In a changed oil market, though, some may question whether these trends will hold. With OPEC leading a charge for maintained production and shifts in the global demand, prices may not recover in the ways observed previously. The pace and intensity of innovation may not respond the way it has before either. To a large extent, this depends on oil companies’ attitudes towards costs and what may be gained from investment in research and development. The trend of oil prices over the last 12 months or so has reminded us that the price of oil is a function of supply and demand: this means that producers may now have to become much more alert to methods of controlling costs. But that may actually be a stimulus to innovation within the industry. Already, many oil companies are looking very closely at the methodology of oil production and refining. Based on the Thomson Reuters awards, many oil companies have, to their credit, been ahead of the curve, perhaps foreseeing a more competitive market, and a renewed need to innovate. NEWSBASE
What next? In other words, oil companies are essentially on a quest to find ways of producing more oil using the same resources and budgets as before. By definition, this process requires expenditure on research and development and implementation of new ideas and techniques. We have also seen a policy among oil companies in Russia towards import substitution, including in areas of technology. Indeed, many Russian oil companies have adopted a stated policy of trying to become more self-reliant in the development of technology for upstream activities, rather than importing (often more costly) technology and know-how. This strategy has parallels in other markets. China is a net importer of oil and gas, so its focus could become more closely connected with domestically generated innovation in the downstream and oil refining sectors. Because China relies extensively on imported hydrocarbons, security of supply is a matter of deep political significance, and that is most likely to remain a motivating factor in stimulating China’s impressive innovation efforts. As it foresees the rising need for energy, China may attach even greater importance to issues of innovation and development for greater self-reliance. At a global level, it may be that all oil and gas companies will now actually see a need to boost budgets for innovations and new techniques in order to remain competitive in a lower oil price environment. The old adage that “necessity is the mother of invention,” may well hold true for stressed producers as they continue to seek more efficient and lower-cost methods of operation. n You can access the Thomson Reuters “State of Innovation” report here: http://stateofinnovation.thomsonreuters.com/
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InnovOil
August 2015
COMMENTARY
Big Foot in big trouble?
Source: US National Marine Sanctuary
As Chevron engineers examine what caused the sinking of nine tendons at its Big Foot platform, Ros Davidson explores some of the possible theories and what they mean for deepwater production
The Big Foot development
F
or weeks, engineers and commentators have been holding their breath for news of what went wrong when nine of the 16 tendons for Chevron’s Big Foot platform lost buoyancy and sank to the ocean floor in late May. The Big Foot field is among the largest and deepest oil discoveries in the Gulf of Mexico, and the landmark project is set to be the world’s deepest tension-leg platform (TLP), as well as the first such platform that Chevron would have installed in the region. Yet this new setback means the project will be delayed for a second time, with costs bound to increase even further. “Tension-leg platforms have been used [in the Gulf] since 1994, so it’s kind of odd that this happened,” said IHS field development specialist Kory Kinney, in an interview with InnovOil. “We’ve never seen anything like this before.” Observers have also remained quiet regarding the cause of the surprise failure, and nothing has been said publicly by Chevron. There were no injuries or release of hydrocarbons associated with the incident. In the loop? The tendons were to have been used to tether the Chevron platform – in Big Foot’s case, one that uses dry trees and with an on-board drilling rig – to a foundation on the seabed 5,200 feet (1,600 metres) below the surface. While the tendons had been pre-installed at the Walker Ridge site, the
US$5.1 billion, 30-stories tall platform had yet to be towed there. During pre-installation, the Big Foot tendons were being held in place by buoyancy modules. As Chevron spokesman Cameron Van Ast explained to InnovOil, it was these modules which lost buoyancy. When they did, the mile-long tendons – which range in diameter from 24 to 32 inches (61 to 81 cm), and are structured like inter-locking pipes – then sank to the bottom. The ocean depth at the current deepest TLP in the Gulf is just under 4,400 feet (1,340 metres). Some experts have speculated that the cause of the Big Foot tendon failure may be the region’s strong loop current: it can act like an underwater hurricane, buffeting oilfield cables and in this case potentially causing the floatation buoys to take on water between May 29 and June 4. The Walker Ridge is especially prone to the phenomenon, where a warm ocean current flows northward between Cuba and Mexico’s Yucatán Peninsula into the Gulf, before looping south-eastwards and flowing between Cuba and Florida back out to the Atlantic. Fierce eddies can spin off the main current, perhaps resulting in the failures seen here. NEWSBASE
Whether such speculation is accurate or not, the equipment failure highlights the risks of deepwater development, where timetables are already far longer than they are onshore or in shallow waters – and where delays and cost over-runs are standard. That includes the deepwater Gulf of Mexico, where Chevron is one of the major leaseholders. Van Ast offered no definitive conclusions as yet, telling InnovOil that “We’re assessing damage to the tendons and undertaking an investigation to determine the exact cause.” After the failure, Chevron quickly established a command centre in Houston, and has been working with relevant regulators from the US Coast Guard and the Bureau of Safety and Environmental Enforcement. Four remote-operated vehicle robots equipped with cameras and 13 ships were deployed to the field site. As of the second week of July, a few boats and ROVs were reportedly still assessing damage. Staying afloat The Big Foot platform remained some distance away, in what Chevron says is “secure” location, though operators will be keeping a weather eye on the horizon – the 2015 hurricane season officially began on
August 2015
InnovOil
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COMMENTARY Xxxxxxx Chevron’s Big Foot platform
June 1 and will end on November 30. Van Ast said that Chevron would provide guidance on the project schedule at its second-quarter earnings call, on July 31, shortly after InnovOil goes to press. But with the sinking of the tendons, the entire project has been delayed indefinitely. Neither is it clear how much Chevron will be able to divulge during the earnings call about the cause of the malfunction. If the cables cannot be salvaged, fabrication of new tendons will clearly take time – and they are pricey – in addition to the extra engineering studies that will be required. The impact on Chevron’s bottom line because of delayed production has also been the subject of much speculation. Initially, production was originally expected at Big Foot in November 2014, but in the first delay an especially strong loop current prevented the supermajor from transporting the Big Foot platform to the field site for four months. The timetable for first oil was then moved to late 2015, according to the company’s website. If successful, it would be one of six new deepwater projects to become operational this year. Chevron – which has a 60% stake in the project, alongside Statoil’s 27.5% share and
Marubeni Oil & Gas’ 12.5% – had originally expected to extract 8,000 barrels per day of crude from the field in 2015, and 30,000 bpd in 2016. The project is ultimately designed to reach 75,000 barrels of oil and 25 million cubic feet (700,000 cubic metres) of natural gas per day. The field, Walker Ridge Block 29, holds estimated recoverable reserves of 200 million barrels of oil equivalent. In the short term, delays will have a small impact on Chevron’s plans for a 20% increase in global production by the end of 2017. Spokesman Kurt Glaubitz recently told Bloomberg that these would account for a loss of around 4.5% (25,000 bpd) of the 549,000 bpd target. Back in the water “Clearly there is no hope for a near-term fix,” Raymond James analysts commented in June. “The project could be back up and running in a year,” suggested Kinney, adding that progress could be hampered, as installation might not be possible during the winter. Chevron would appear to have come to a similar conclusion, with a recent press statement affirming that “First production will not commence in late 2015 as planned.” NEWSBASE
Whatever the result, the failure is unlikely to force a re-think of current assets in the Gulf. TLP designs have long been considered a sound development solution for hurricane-prone waters, and it should be noted that incidents such as this have proved rare. These production facilities allow horizontal movement but not any vertical movement – roughly speaking, this means no bobbing. “Therefore when large waves rush by, such as in a hurricane event, the platform remains stable in the water,” Kinney explained. “TLPs are able to be fabricated and commissioned quayside as opposed to offshore. They also have a proven performance record, so it is a safe choice [for an area such as the Gulf],” he said. Indeed, there are more than 10 TLP platforms currently operating in the region, none of which have malfunctioned in the same way. “The Big Foot situation is an anomaly,” Kinney concluded. But with companies already under strain from low prices and delays in major projects, a setback such as this will be a test of both the engineering capabilities of the Gulf, and the resilience of a supermajor such as Chevron. n
InnovOil
page 34
August 2015
News in brief
Maersk claims record for Egypt well Maersk Drilling has drilled the deepest well ever in Egypt – and the longest in the Mediterranean Sea – earlier this year during work for BP. On July 6, the drilling company released a statement announcing that its Maersk Discoverer semisubmersible had completed the Atoll-1 on the North Damietta Offshore concession, in the East Nile Delta, on May 5. This was 62 days ahead of schedule, “thereby creating a substantial cost saving”. In March, BP said the Discoverer had reached a depth of 6,400 metres while drilling the Atoll-1, encountering approximately 50 metres of gas pay in highquality Oligocene sandstones. This followed a previous discovery by the company at its Salamat well in the same concession. “The strong performance is a result of the dedicated use of the ‘Plan Do Study
Act’ methodology in the planning and execution of the work,” said Maersk’s rig leader, Allan McColl. “Also, a structured approach to applying lessons learned from the previous wells, Geb and Salamat, played an important role.” He went on to say that the company had used observation studies to “optimise operational performance as a key driver in continuously improving the operational procedures”. An example of this was the use of an auxiliary well centre as a “test bed” to break the bottomhole assembly handling process into steps, while previous maintenance on the blowout preventer (BOP) before the well was drilled also allowed it to keep functioning on the wellhead for no less than 201 days. In March, Egypt and BP signed a memorandum of understanding (MoU) covering a US$12 billion new investment, a move widely seen as marking an upturn in the fortunes of the country’s energy sector following the revolution in 2011. BP’s West Nile Delta project intends to develop 141.6
billion cubic metres of gas and 55 million barrels of condensate. Production will reach 33.99 million cubic metres per day, it said, and start up in 2017. Edited by Ed Reed edreed@newsbase.com
FEEDing time at Ophir’s Fortuna Ophir Energy has awarded front-end engineering and design (FEED) contracts for its Fortuna floating LNG (FLNG) project, in Equatorial Guinea. The company also raised the possibility of adding a second FLNG vessel to the development. In a statement on July 9, Ophir said FEED contracts had been awarded to two consortia. The first is McDermott Marine Construction and GE Oil & Gas UK, while the second is Subsea 7 and Aker Solutions. Upstream FEED would be a competitive process, with the two groups submitting
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August 2015
InnovOil
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News in brief
engineering, procurement, construction, installation and commissioning (EPCIC), with Ophir choosing one group for the final investment decision (FID). FEED work should be completed by the end of 2016 with an FID in mid-2016 – and first gas expected in mid-2019. Studies from the competing consortia will define the number of wells required to reach first gas, the cost of the development and the delivery time of the long lead subsea items. “The FEED awards, to industry-leading contractors, follow a strongly contested first phase, reflecting the industry’s grasp of the significance, and advanced prospects, of the Fortuna project,” Ophir’s CEO, Nick Cooper, said. Golar LNG is to build, own and operate the FLNG vessel, the Gimi, under a tolling contract, Ophir said in May. Golar will carry out its own FEED study on the midstream part of the project, starting shortly. The Gimi is expected to have capacity of around 2.2 million tonnes per year. The first phase of the project is backed by 45.3 billion cubic metres of contingent resources at the Fortuna and Viscata gas fields. There is another 28.3 bcm of contingent resources available for development, with a further 25.49 bcm of low risk prospective resource. As such, Ophir is considering a second FLNG vessel to exploit these resources. A decision on this would be made once production had started via the first vessel, with a projected start-up of around 2025. “Ophir’s focus will now switch to securing buyers for the LNG offtake and to bringing in an equity partner prior to our mid-2016 FID. Numerous potential counterparties have recently expressed interest in the offtake and partnering opportunities,” Cooper continued. Choosing FLNG over a conventional onshore development has reduced costs from around US$3 billion to US$800 million, he continued, while accelerating the speed at which it can be brought online by two to three years. Tudor Pickering Holt noted the FEED award was a rarity in West Africa’s offshore, given the industry’s current circumstances, but also that investors were “extremely sceptical” of the project. FirstEnergy Capital, meanwhile, said securing buyers for LNG offtake would be key in reducing the development’s risks. Edited by Ed Reed edreed@newsbase.com
OneSubsea Announces Global Alliance with Subsea 7 OneSubsea, a Cameron and Schlumberger company, announced today that they have signed an agreement establishing a worldwide non-incorporated alliance with Subsea 7 to jointly design, develop and deliver integrated subsea development solutions through the combination of subsurface expertise, subsea production systems (SPS), subsea processing systems, subsea umbilicals, risers and flowlines systems (SURF), and life-of-field services. The alliance will bring together Subsea 7’s experience and technology in seabed to surface engineering, construction and lifeof-field services with OneSubsea’s unique reservoir expertise and state-of-the-art subsea production and processing systems technologies. The alliance will combine both companies’ resources to collaborate on selected projects, engaging early to improve field development planning from the reservoir to the production facility. By combining the complementary capabilities and market-leading technologies of Subsea 7 and OneSubsea, the alliance will work collaboratively with clients to design, develop and deliver integrated SPS and SURF solutions, which will enhance project delivery, improve the recovery, and optimize the cost and efficiency of deepwater subsea developments for the life of the field. “The technology and expertise from Subsea 7 perfectly complements OneSubsea’s Pore to Process™ business strategy to offer a holistic approach to subsea development solutions,” Mike Garding, OneSubsea Chief NEWSBASE
Executive Officer, said. “Our established competencies in subsurface modelling and production systems engineering will be further strengthened by integrating the SURF expertise provided by Subsea 7. By integrating these key areas of expertise, we can further reduce risk and uncertainty to deliver the optimal solution for our clients to produce cost-effectively from subsea reservoirs.” Jean Cahuzac, Subsea 7 Chief Executive Officer, said: “This combination of subsurface, SPS, SURF and life-of-field expertise is unique in its breadth of integrated service offering and provides clients with the opportunity to significantly improve subsea field economics over the lifetime of the development. I am looking forward to developing further our relationship with OneSubsea as we will be able to capitalize on the synergies between our strong technology portfolios and develop joint technologies to improve our offering for our clients.” ONESUBSEA
Pertamina turns to foreign firms for help with refinery upgrades Indonesian state oil firm Pertamina is planning to expand and upgrade four major refineries at a cost of US$25 billion, which will require help from foreign partners.
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InnovOil
August 2015
News in brief BP p.l.c.
The improvements will take six years and will involve Balikpapan in Kalimantan, Cilacap in Central Java, Dumai on Riau Islands and Balongan in West Java, Pertamina’s processing director, Rachmad Hardadi, told local media. The upgrading plans have come after Pertamina failed to secure the support of two Middle Eastern oil firms to help build two new 300,000 barrels per day refineries. Japan’s Nippon Oil and Saudi Aramco have expressed an interest in participating in the expansions plan, Rachmad was reported by the Jakarta Post as saying. Nippon is likely to be involved in expansion work at the Balikpapan refinery to increase its capacity by 100,000 bpd to 360,000 bpd, the newspaper said. Indonesia has not built a new refinery since 1994 and domestic demand for fuel oils exceeds supply from the country’s eight refineries by 500,000 bpd. The existing refineries were thought to have a combined capacity of 1.1 million bpd, with Cilacap the biggest at 340,000 bpd. However, industry sources have said total capacity has now dropped below 1 million bpd because of ageing equipment. Long negotiations between Pertamina and foreign oil firms to build two new 300,000 bpd refineries ended without an agreement being reached in October 2013 over tax issues. The talks were being held with Saudi Aramco and Kuwait Petroleum Co. (KPC).
Indonesia could become the world’s largest importer of gasoline by 2018, Wood Mackenzie has predicted. The country has the world’s fourth largest population, now at over 250 million. It has increased by 50 million since year 2000. Pertamina’s gasoline imports in April and May were over 10 million barrels per month, according to Platts data. Indonesia’s Ministry of Finance said last week that Jakarta would seek large loans from the new China-led Asian Infrastructure Investment Bank in order to develop infrastructure. Edited by Andrew Kemp andrew.kemp@newsbase.com
BP installs topside modules for Clair Ridge platform BP and its partners have installed the first topside modules for the new Clair Ridge platform in the UK North Sea. This marks a big step forward for the project, which is seen as key to the country’s future energy security. Three topside modules have been installed on the “quarters and utilities” (QU) platform, which lies 75 km west of the Shetland Islands, after being delivered NEWSBASE
from South Korea and safely lifted onto pre-installed jackets by the Heerema Thialf deepwater construction vessel. Trevor Garlick, regional president for BP’s North Sea business, described the installation as a “fantastic achievement” for the project. “In a challenging time for the industry, the project shows the potential of our basin and why it’s so important that we work to ensure a competitive future business,” he said. Around half of the investment associated with the Clair Ridge project is being directed towards the UK, with more than 80 British companies providing engineering design and support, hook-up and installation services, plus equipment and man power, according to BP. The hook-up and commissioning of the topside modules by Amec Foster Wheeler created more than 600 jobs, including six electrical apprentices. To limit the project’s environmental impact, the platforms will be powered using dual-fuel power generators incorporating waste heat recovery technology. Vapour technology will also be used to capture and recycle low-pressure gas for use as fuel or for exporting to shore. BP and partners ConocoPhillips, Chevron and Royal Dutch Shell aim to produce 640 million barrels of oil from the Clair field over 40 years. At its peak, it is expected to produce 120,000 barrels per day of oil. Although discovered in the 1970s, the field was not brought on stream until 2005, owing to its location and geographical complexity.
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InnovOil
page 38
August 2015
News in brief
It will be the first ever large-scale project using salt-water injection technology to enhance recovery. The Clair Ridge project will target a northern area of the field and comprises two new bridge-linked platforms plus pipeline infrastructure for the export of oil and gas to Sullom Voe in Shetland. The next big milestone for the project will be the installation in summer 2016 of production drilling platform topside modules. First oil is anticipated in 2017. Edited by Ryan Stevenson ryans@newsbase.com
Statoil to test CO2 well stimulation in Bakken shale Norway’s Statoil is preparing to begin stimulation testing using a carbon dioxide (CO2) enhanced oil recovery (EOR) method at its Bakken shale acreage in North Dakota later this year. The test will be carried out at a site about 15 miles (24 km) from Williston. The test is aimed at evaluating any potential uplift in production uplift and at partially replacing the water required for multistage hydraulic fracturing, according to Statoil. After using CO2 in the initial fracking
stages, the stimulation will be completed by using a more standard mixture of water and proppant. The well stimulation test is one of several projects being carried out by Statoil’s joint technology programme with General Electric, known as Powering Collaboration and aimed at boosting sustainability in energy. CO2 is commonly used in well stimulation in the Western Canadian Sedimentary Basin, but this will be the first major application of liquid CO2 to displace slickwater during the fracking process in the Bakken, Statoil said. The company anticipates being able to use 20-40% less water than usual in the test phase for the initial stimulation. It also expects that using this method could boost recovery by 20-25% based on modelling and laboratory experiments. Statoil is ultimately planning to further reduce water use during the stimulation process. If the test results are positive, the next step will be to design a method to capture the CO2 as it flows back and reuse it to stimulate additional wells. Statoil holds roughly 265,000 net acres (1,072 square km) in the Bakken, where its production earlier this year was reported as being roughly 59,800 barrels of oil equivalent per day from interests in 512 operated wells. Edited by Anna Kachkova annak@newsbase.com
Statoil’s Bakken shale acreage in North Dakota
NEWSBASE
Shell makes FID on Appomattox deepwater project Royal Dutch Shell has announced that it has made a final investment decision (FID) on its Appomattox deepwater project in the US Gulf of Mexico. This comes after the company achieved cost reductions that will make the project economic even in a low oil price environment. The development will initially produce from the Appomattox and Vicksburg fields, with average peak production estimated to reach roughly175,000 barrels of oil equivalent per day, the company said. The sanctioned project includes capital for the development of 650 million boe of resources at Appomattox and Vicksburg, and start-up is anticipated around the end of this decade. The Appomattox floating platform will be Shell’s eighth in the Gulf, as well as its largest. The company will now proceed with construction and installation. “Appomattox opens up more production growth for us in the Gulf of Mexico, where our production last year averaged about 225,000 boe per day, and this development
August 2015
InnovOil
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News in brief
will be profitable for decades to come,” Shell’s upstream director for the Americas, Marvin Odum, said. Shell said that during its design work for Appomattox, it had brought down the total project cost by 20% through supply chain savings, design improvements, and by reducing the number of wells required for the development. This included advancements from the company’s previous four-column hosts, such as the Olympus tension-leg platform (TLP). With these and other cost reductions, Shell estimates the project’s breakeven price to be around US$55 per barrel Brent equivalent. The Appomattox and Vicksburg fields are in the Norphlet formation. Shell is currently the only operator with commercial discoveries in the Norphlet and is continuing exploration in the region. The development of Shell’s recent, nearby discoveries at the Gettysburg and Rydberg prospects remains under review, the company said. If development of these goes ahead, they could become additional tiebacks to Appomattox, bringing the total estimated discovered resources in the area above 800 million boe. Shell owns 79% of the Appomattox project, with Nexen Petroleum Offshore, a wholly owned subsidiary of CNOOC Ltd, holding the remaining 21%. Edited by Anna Kachkova annak@newsbase.com
PDO launches large-scale solar EOR scheme Petroleum Development Oman (PDO) signed a deal in early July with US-based GlassPoint Solar for the construction of a large-scale solar thermal plant to fuel a steam-based enhanced oil recovery (EOR) project at the Amal West field in southern Oman. The Californian firm, formed in 2009 with a focus on solar power generation for use in the oil and gas industry, commissioned a pilot at the field in 2013 and deepened its ties within the sultanate in September 2014 through a capital-raising initiative subscribed to by the government’s State General Reserve Fund (SGRF) and Royal Dutch Shell – which owns 34% of PDO, the sultanate’s largest hydrocarbons producer. With energy-intensive tertiary recovery accounting for a steadily increasing
proportion of the Omani producer’s output at the same time as the country faces a growing gas shortage, alternative power sources are highly attractive. PDO is planning a 1,021-MW solar thermal plant at a cost of around US$600 million, to be designed and built by GlassPoint using the firm’s enclosed trough system of concentrated solar power (CSP) technology, which it advertises as being specially designed for deployment at oil and gas fields situated in harsh geographical environments such as that of Oman. The pilot at Amal West was the firm’s second project and the first to be implemented outside its native California. Commissioned in May 2013, the 7 MW plant produces an average of 50 tonnes per day of steam – fed directly into PDO’s steam network for EOR at the field – and was envisaged as a test for large-scale use of the technology at the same location. Ground is due to be broken on the new plant – Miraah – later this year with the first module due on stream in 2017. The deal was presaged in September 2014 when the SGRF and Shell committed US$53 million during a capital-raising exercise by GlassPoint aimed at funding expansion into larger-scale generation in Oman. Launching the Miraah project, PDO estimated an annual natural gas saving of 5.6 trillion British thermal units (Btus, 156 billion cubic metres) when the plant becomes fully operational, while GlassPoint’s headline claim is that its technology, whereby the steam is generated by concentrating sunlight rather than by burning gas, reduces gas consumption and carbons emissions at oilfields by up to 80%. Around 25% of total gas consumption in the sultanate is absorbed in oil production and such demand has been growing alongside the increasing use of EOR technologies to stem or replace declines in NEWSBASE
conventional production at maturing fields. By 2023, PDO expects around 33% of total crude output – now running at around 570,000 barrels per day – to be produced using tertiary recovery techniques. The steam injection project at the Amal West and East field was launched in 2010. Signing the latest deal with GlassPoint, PDO managing director Raoul Restucci intimated that the use of solar-powered EOR might be extended to other fields in the company’s Block 6 concession area. “The use of solar for oil recovery is a long-term strategic solution to develop PDO’s viscous oil portfolio and reduce consumption of valuable natural gas,” he said. “It also will displace diesel and higher carbon-intensive power generation and oil burning in future thermal projects.” Despite the obvious advantages for Muscat in exploiting its considerable wind and solar power potential, the government has been somewhat slow in developing renewables – even by regional standards. However, the increasing acuteness of the gas shortage appears to be galvanising activity: the main contract on the sultanate’s first large-scale wind farm – at Harweel in the remote southern Dhofar governorate – is due to be awarded by the end of the third quarter for commissioning in 2017, while a licence was issued earlier this month by the Authority for Electricity Regulation for the country’s maiden solar photovoltaic (PV) plant – a pilot project to be developed in the Al-Mazyounah area of Dhofar by the local/ Indian Bahwan Astonfield Solar Energy Co. The government’s Oman Power & Water Procurement Co. intends to launch projects by the end of the year for the development of up to 200 MW of solar power capacity, according to the organisation’s 2015-21 plan published in April.. n Edited by Ian Simm ians@newsbase.com
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August 2015
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 GPUSA’s Distributed Seismic Source™ technology, and how it could change the way in which surveys are performed, contact CEO James Andersen at sales@gpusa-ca.com or call +1 (747) 224 0315 To attend SPE Offshore Europe 2015, visit www.offshore-europe.co.uk/ and register online For more information on KONGSBERG’s integrated control and safety systems (ICSS) and how it could be applied to your vessel or platform, contact Offshore Production Systems Sales Manager Dean Jennings, on +44 (0) 1224 278 300 or email dean.jennings@kongsberg.com To hear more about Teledyne Marine Systems’ costeffective and versatile subsea solutions, contact Alasdair Murrie at Teledyne Seabotix at alasdair@seabotix.com or Arnar Steingrimsson at arnar.steingrimsson@teledyne.com . You can also visit www.teledynemarine.com To enquire about composite repairs and their standards, contact Ian Taylor at IMG Composites on +44 (0) 1224 879 966 or email ian.taylor@imgcomposites.com For more information on patents and technology, you can access the Thomson Reuters “State of Innovation” report here: http://stateofinnovation.thomsonreuters.com
NEWSBASE
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