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Decom developments P&A solutions, collaboration and more Page 15
Eye on batteries
Hotter batteries could power downhole equipment Page 26
Eelume-inating the depths
Norway’s subsea snake ROVs Page 9
June 2016
InnovOil
June 2016
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Inside Contacts: Media Director Ryan Stevenson ryans@newsbase.com
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An x-ray of hope
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Snakes in the grass
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3-D pictures of the inside wells
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Sea-dwelling robots for IMR operations
DNV’s WINning formula 10 Wind-powered water injection JIP
Editor Andrew Dykes andrewd@newsbase.com
On the radar
What caught our attention outside the world of oil and gas this month
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News in brief
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Rigless P&A techniques
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Interwell is using thermite to melt rocks and seal wells
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Boron nitride at greater temperatures
ction and refining tions in exploration, produ June 2016 Bringing you the latest innova Issue 43
DECOM DEVELOPMENTS P&A solutions, collaboration and more
Energy firms must up their game
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EYE ON S BATTERIEes could Hotter batteri power downhole equipment Page 26
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EELUME-INATING THE DEPTHS
ROVs Norway’s subsea snake
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A note from the Editor Mergers and acquisitions, it seems, are like buses. Industry analysts – and employees – waited 18 months for Halliburton and Baker Hughes to conclude talks, agree terms and negotiate anti-trust hearings, only for these ultimately to scupper the deal. Indeed, Deputy Assistant Attorney General David Gelfand with the US Department of Justice’s Anti-trust Division argued that the merger would have “raised prices, decreased output and lessened innovation in at least 23 oilfield products and services critical to the nation’s energy supply.” Given the long wait, and the rollercoaster of oil prices in the meantime, the value of the deal had declined to around US$28 billion by the time it was scrapped. Yet another flurry of activity – and some speculation – saw a raft of deals arrive all at once in these past few weeks. Most notably, FMC Technologies and Technip announced their intention to combine to create TechnipFMC, a US$13 billion company described by the two as “a leader in subsea, surface and onshore/offshore, driven by technology and innovation.” In some ways it is unsurprising – the deal builds on the work of Forsys Subsea, the firms’ joint venture launched in 2015, which aimed to maximise cost and efficiency by bringing engineering teams together as early as possible during subsea projects. We can deduce that the experiment was a success. Moreover, its creation marks the new company’s entry to the “big league” of oil services, as some analysts have put it, and a partnership capable of challenging the Big 3 firms.
News of a US$4.4 billion takeover of the US’ Memorial Resources by Range Resources broke on May 16. Meanwhile, whispers abound – the latest being a rumoured bid for Apache by Occidental Petroleum, albeit one of which both companies have denied any knowledge. All this has commentators tentatively speculating that more mergers are on the cards, potentially signalling a turning point if buyers now anticipate a price rebound. It is by no means conclusive, but it does mark the end of a prolonged period of little action in the market. From an innovation perspective, new collaborative agreements and corporate models are as encouraging as new equipment. This month we speak to Exceed, which aims to offer just such a model in order to become a decommissioning “one-stop shop.” The company’s commercial director, John Anderson, tells us more in our decom-focused supplement. If you prefer your innovations robotic, x-ray emitting or face-meltingly hot, we still have plenty of that too. This month, Norway’s Eelume unveiled a snake-like subsea robot for use in subsea IMR, both the most interesting and most terrifying thing we have seen this year. Visuray also shows us how to see inside wells with x-ray imaging, and we explore Interwell’s thermite-based solution for plugging and abandonment. All this, as well as temperature monitoring from LumaSense Technologies, the importance of cybersecurity, rigless P&A solutions and more… The team and I are pleased to present the June edition of InnovOil.
Andrew Dykes Editor
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InnovOil
June 2016
An x-ray of hope for stuck tools Visuray is using x-rays to give operators detailed 3-D pictures of the inside of their wells
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With its unique downward focused X-ray source, the VR90 tool is shown imaging the fishing neck of a wireline tool stuck in a well
hat if you could see inside your well? The instinctive is answer is that with various imaging techniques, we already can. Cameras, electrical, acoustic and combination imaging techniques already offer a multitude of methods which enable us to examine or map the condition and layout of the wellbore – yet the value of those images depends on what exactly you need to do. The major problem with optical imaging is that it requires a transparent fluid to be of any help – few cameras can see through opaque liquids. Ultrasonic techniques work with clear fluids but are less useful for fluids contaminated with particulates. Stuck tools represent a particular problem. If a tool gets stuck downhole during a well intervention, options are limited in terms of its retrieval, especially when intervention engineers or slickline operators cannot see exactly what is going on. Impression blocks can be used, but do not offer much clearer insight than that suggested by a misshapen block of metal. Furthermore, even if the tool can be located and its position established, it is usually very difficult to retrieve it one piece with such a limited view. Visuray’s approach is a departure from the industry norm; in a process called fluid-based surface imaging, it uses x-ray backscatter to produce highly detailed 2-D and 3-D images of hardware in the well. Seeing is believing The firm offers downhole x-ray imaging as a commercial service to operators looking to their wells in greater detail – particularly useful when undertaking well interventions. Its proprietary system, the VR90®, is a downward-facing x-ray tool which can be deployed downhole via coiled tubing and run via all types of electric wireline. Inside the VR90 is a digital x-ray detector with a pixelated array based on applications from the medical sector, as well as a miniaturised, high-output x-ray source. NEWSBASE
To power this, Visuray developed a compact, ultra-high output power supply which enables the 180-kV source to emit high-energy x-rays, using an electron beam current of 1mA. All of this is housed in a system measuring 3 5/8” (92mm), around 27.5 feet (8.4m) in length and weighing 236kg. Miniaturising this technology was one of the Visuray team’s greatest challenges. The firm’s founding CEO and chief technologist, Phil Teague, explained to InnovOil: “We generate and control very high voltages within a very narrow grounded tool housing. State-of-the-art industrial power supplies of an equivalent voltage are similar in size to an oversized suitcase but only operate at room temperature – so reducing the size of such power supplies into a wireline deployable 3 5/8” tool while designing for hightemperature functionality was one of the key successes of the technology development.” The detector itself is made up of six individual tiles measuring 128x128 pixels, each pixel of which measures 100 square micrometres. Information gathered by the array is then sent back to the surface for processing, generating 2-D and 3-D images for analysis by the operator. Rather than this being taken away to be processed, images can be produced in near real time, allowing intervention managers to make faster decisions about their wells. The actual process enabling this is more complicated than it may sound. In backscatter imaging, the radiating source and the detector are positioned on the same side of the examined object. Traditionally, the detector is calibrated to form an image from the photons which are scattered and returned by the object – yet the metals used in oil wells tend to be very dense and will readily absorb photons. In addition since the object is immersed in the well fluid, the signal which returns is mostly comprised of backscatter from the fluid. That rules out using a simple x-ray backscatter setup. Visuray navigates this problem using its
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June 2016
Tool in well
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2-D image
3-D image
Fish
Wire ball
Wrench
In all three cases, VR90 images allow operators to select the correct fishing tool for successful recovery.
proprietary technique. Fluid-based surface imaging assumes that photon scattering occurs mainly in the fluid with only a negligible contribution from the object itself. That means that the amount of scattering observed indicates the distances between the detector and the face(s) of the metal object. Using this principle, Visuray’s system reconstructs a 2-D and 3-D image of the object based on these spatial variations. This inherently safe method can deliver a clear picture across all production fluids, even when they contain particulates such as sand or rust. It can also image hardware as it lies, without the need for cleaning, additional fluid displacement or chemical conditioning, all of which offers a considerable time and cost saving compared to other techniques. Gone fishing Another particular advantage – though by no means a necessity – is that the 3-D image can be rendered in other ways. In conversation with InnovOil, Visuray demonstrated a 3-D printed resin model of a wrench, which had been modelled from a 3-D x-ray image. While it is unlikely to be useful to
all operators, having an actual model of the tool to examine is a powerful physical tool to show just how accurate and informative the technique can be. Currently, the VR90 works at temperatures of up to 100 °C and pressures of 20,000 psi, though recent improvements will see a 125 °C-rated model brought to market later in 2016. Teague says that this covers temperatures found in “the majority of wells,” but rules out high-temperature applications for the moment. “Wells with significantly higher temperatures, such as 150 °C, are currently prohibitive to the technology. However, we are continuing to increase the temperature rating of the technology and believe that we will be able to service the [these] wells in the future.” Visuray remained drawn on the provisional cost of the service – Teague told InnovOil that the service was “comparable to the cost of running other imaging services” – but added that once the technology had proved its worth, a value pricing method would be agreed with its customers. Promisingly, those potential customers could be major operators – Statoil, BP and Royal Dutch Shell all contributed funds to the company’s initial start-up, with additional funding supplied in a later round by other joint industry partners. So far, Teague said, “industry response to the technology has been very positive.” NEWSBASE
Late 2015 saw the company secure its first commercial well operation, where it used the VR90 to take 2-D and 3-D images of a coiled tubing BHA disconnect in an onshore well in the Netherlands, for TAQA Energy. As a result of the image accuracy, the assembly was retrieved in a single fishing run. Beyond its direct use in imaging, Teague believes the technology holds a number of other possibilities that the company hopes to explore in future, adding: “It is possible to envision applications where it can be employed as a well integrity diagnostic method. The way in which we produce X-rays also eliminates the use of radioactive isotopes, [meaning that] many of the traditional oilfield measurements which rely on radioactive materials could be replaced with this core technology, in addition to new techniques and measurements.” Overall, it is a highly promising innovation for an industry just beginning to get to grips with x-ray techniques in areas such as asset integrity and inspection. With even more focus being placed on cost and time efficiency, in new wells and old, the accuracy offered by the VR90 could make it an invaluable tool for the tech-savvy well manager. n Contact: Angeline Tse
Email: angeline.tse@visuray.com Web: www.visuray.com
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Cost cutting
Improved cost-cutting and cost estimation is fundamental in the low-price environment. We discuss enhanced cost-optimisation strategies with Amec Foster Wheeler.
Brent’s big lift
High-profile projects remain on course, such as the removal of Shell’s Brent Delta platform’s topside in the North Sea. We spoke to the project’s director to gain crucial and exclusive insight.
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Finding new solutions to old problems is critical in the decommissioning field. We look at lessons that can be learned from nuclear power decommissioning and other sectors.
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InnovOil
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Eelume gets kraitive with subsea robot
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EYE ON BATTERIE Hotter batter S
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Cover story
EELUME-IN THE DEPT ATING
Norway’s sub HS sea snake ROV s
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A new joint project unveiled by Statoil, Kongsberg Maritime and robotics developer Eelume will explore sea-dwelling robots for IMR operations
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phidiophobes beware: robotic snakes may soon be lurking in the Norwegian Sea. Kongsberg Maritime and Statoil have signed an agreement with Eelume to develop swimming, snake-like robots for subsea inspection, maintenance and repair (IMR). Eelume, a Norwegian University of Science and Technology (NTNU) spin-off, has been developing the technology with Sintef, an independent research centre, for over a decade. Opinion might be divided over whether these robots look like the future or the stuff of nightmares, but either way they have an undeniable cool factor. Their snake-like, flexible form allows them into confined areas which have proved difficult to access with existing technology. The ability to rotate the head of the robot fully also means that they can grasp and turn valves and handles in the same manner as an ROV manipulator arm – but without the bulky ROV attached to it. The demonstration videos released by Kongsberg illustrate just how dextrous the robot is. Two versions are also highlighted: one with tail-mounted thrusters and one which is propelled by a swimming motion alone. In the test pool, both appear tethered to umbilicals – a design which presumably is not intended for a final concept. The group suggests that the robots would be permanently installed on the seabed – Eelume calls this a “resident solution” – and would then perform planned and on-demand inspections and interventions. “Instead of using large and expensive vessels for small jobs, we now introduce a flexible robot,” explained Statoil CTO Elisabeth Birkeland. Perhaps a little diminutively, Birkeland likens them to “a self-going janitor on the seabed.” They can be deployed at both existing and new fields where typical jobs include: visual inspection, cleaning, and adjusting valves and chokes – jobs which represent the majority of the costs of inspection and intervention. “This partnership offers the chance to
Executive Vice President Kongsberg Maritime Subsea Division, Bjørn Jalving (second right) and Statoil CTO Elisabeth Birkeland Kvalheim (right), investigate the Eelume prototype. bring radical technology to the market, not just in what the Eelume robot can do, but how it does it,” commented Kongsberg Maritime Subsea Division executive VP, Bjørn Jalving. “It is a new tool that will enable operators to realise large-scale cost savings by introducing new ways of conducting routine tasks and helping prevent unscheduled shutdowns by reacting instantly when required.” “With our unique expertise in the field of snake robotics Eelume is the first company in the world to bring these amazing robots into an industrial setting. Now we take the step from academia and into the commercial NEWSBASE
world to secure our place in the new and exciting subsea intervention landscape,” Eelume CTO Pål Liljebäck added. InnovOil asked Kongsberg Maritime whether it had any further information on the cost, capabilities or time frame for the robot’s development. Given the early stages of the project the company was reluctant to reveal much, but said that its aim was to commercialise the technology specifically for oil and gas operations. More work will be carried out over the next 18-24 months, and the group hopes to release further details towards the end of the year. n
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DNV continues with WINning formula
DNV GL announces successful results from the first stage of its wind-powered water injection JIP
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ne of DNV GL’s latest projects is harnessing two things the North Sea has plenty of: hydrocarbons and wind. Last year saw the company unveil WIN-WIN, a joint industry project (JIP) exploring the use of wind as a potential power source for water-injection in oil and gas wells. It has since concluded the first phase of the JIP, finding that such a system is technically viable and – more importantly – commercially feasible. InnovOil covered the project’s early stages over a year ago, at which point it was seeking partners to help develop the idea. By October it had announced its final list of collaborators, with ExxonMobil, Eni Norge, Nexen Petroleum UK, Statoil, VNG, PG Flow Solutions and ORE Catapult all signing on. In December 2015, project sponsor and segment leader of floating wind turbines Johan Sandberg explained that the broad support would prove helpful: “Together, they cover the value chain from wind production and operation, to pump manufacturing, to oil and gas operators.” During OTC 2016, DNV announced the results of JIP’s first phase, adding that the concept “is technically feasible, capable of meeting performance targets, and offers a cost-competitive alternative to conventional water injection solutions.” Twenty’s plenty Its case study offers more information on the injection equipment and the potential layout of the wind turbine. Last year, initial concept designs used a floating turbine structure, and suggested housing pumps internally inside the monopile itself. DNV’s published version still uses one floating 6-MW turbine, but mounts two 2-MW injection pumps on the topside of the spar platform, in addition to the filtration,
chlorination and chemical injection systems. As for the well itself, DNV’s reference case is a North Sea reservoir with two injection wells, located 30 km from production host, 30 km from shore and in 200 metres of water. At maximum capacity, the system’s pumps can move 80,000 barrels of water per day, leaving a very wide margin above the well’s target injection rate of 44,000 bpd. In its Phase 1 report, DNV added that the system’s injection volumes – based on outputs from realistic wind data – typically exceed target rates, even during periods of low wind. In a statement accompanying the news at OTC, Sandberg added that this model demonstrated “a potential cost saving of approximately 20% compared to a conventional solution,” though conceded that “this will of course vary greatly between cases.” DNV calculates CAPEX of around 75 million euros (US$84 million), of which more than half is made up of equipment and marine logistics. OPEX is estimated at around 4.7 million euros (US$5.3 million) per year. While DNV has always conceded that the OPEX is greater, the reduced CAPEX plays a major role in reducing lifetime costs, particularly for injection wells far away from the host platform, or where platform space is limited. All in all, in the aforementioned scenarios, DNV estimates suggest that WIN-WIN’s lifecycle costs are around 0.9 euros (US$1.01) per barrel of water, compared with around 1.2 euros (US$1.35) per barrel using conventional solutions. While a 20% cost reduction is very promising, floating turbines are still in need of some qualification. The most progress so
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far has been made by JIP partner Statoil at its Hywind pilot project – a scheme which will moor five 6-MW floating turbines in 100m of water, 30 km off the coast of Aberdeen. The technological similarities infer a heavy reliance on Statoil’s progress in this particular field – indeed, it is referenced by Statoil’s head of renewable technology development Hanne Wigum in DNV’s release, who notes: “Supplying clean power to oil and gas installations was part of the original idea behind Statoil’s Hywind concept.” Promisingly, DNV says that the study has found “no major challenges” to the concept, and that it is able to meet the partner’s injection volume targets, reliability criteria and need for minimised downtime. Readying Phase 2 At the close of last year, Sandberg suggested that there were a number of potential WIN-WIN models to be explored by operators. Platform owners could take over the operation and maintenance of the turbine and pump systems themselves, he said, or a dedicated business could lease or hire them out to E&P companies. New applications for the system are still being discussed. He added: “The focus has been water injection, but the results from the project are promising enough to start investigating other applications. It is a natural step to take the lessons we have learned here and look at other non- or semi-critical processes.”
With that in mind, DNV is now looking to take on more partners for the project’s second phase. In May, Sandberg explained to InnovOil via email that electrical systems would be one of the group’s major foci, with a view to taking the necessary equipment from a technology readiness level (TRL) of 3, up to a nearly commercial 6. In addition, the partners will look at developing guidelines for the design and running of a WIN-WIN system. Sandberg added: “A next step would be to test critical subsystems in a small-scale physical set-up. The key objective would be to gain assurance that the components integrated in this configuration will offer
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satisfactory performance over time with a variable power input.” That opens the field to new JIP partners and suppliers – in particular those involved in electrical supply, pumping equipment and micro-grid controls. Any capable and interested firms are encouraged to get in touch with DNV ahead of Phase 2. In the meantime, DNV will be hoping to build even more interest in an already WINWINning formula.n Contact:
Are Kaspersen, Project Manager, WIN WIN JIP Tel: +47 416 33 831 Web: www.dnvgl.com/energy
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InnovOil
On the radar
What caught our attention outside the world of oil and gas this month
OceanOne – the friendlier face of subsea robotics Earlier in this issue you saw the incredible and strangely terrifying snake-like ROVs from Norwegian firm Eelume. On the friendlier end of the spectrum is Stanford University’s OceanOne, a humanoid robot built for reaching the places divers cannot. According to the university, OceanOne “is powered by artificial intelligence and haptic feedback systems, allowing human pilots an unprecedented ability to explore the
Liquid power Massachusetts Institute of Technology (MIT) researchers have unveiled a technique for 3-D printing solids and liquids in a single step – allowing them to create a hydraulicallypowered robot requiring no assembly. MIT’s Computer Science and Artificial Intelligence Laboratory (CSAIL) used a modified (but commercially available) 3-D printer to deposit layers of a solid photopolymer and a non-curing liquid. The
June 2016
solid is then hardened using high-intensity UV light, leaving the liquid to flow around the system. In 22 hours, this process allowed the team to manufacture a moving hexapod robot, which was completed by adding a motor and a battery. Internal bellows convert fluid pressure into the robot’s motion, and the whole assembly can be controlled via a smartphone. In a separate print run, the team
also printed a gear pump with continuous fluid flow. Accelerating the process depends less on the particulars of our technique, and more on the engineering and resolution of the printers themselves,” noted Viterbi Professor of Electrical Engineering and Computer Science at MIT Daniela Rus. “Printing ultimately takes as long as the printer takes, so as printers improve, so will the manufacturing capabilities.”
NASA release, the tape changes colour from beige to high-contrast black in less than three minutes at concentrations as low as 0.1% – well before the explosive combustion threshold of about 4%. The pigment is passive – no power required – and is highly resistant to
environmental factors such as ultraviolet exposure, salt spray and humidity, so this is good news for offshore installations and refiners. It has since been patented and licensed as a commercial product to Floridabased HySense Technology, and marketed as Intellipigment™.
Taping a leak This month we came across some interesting leak detection technology pioneered by NASA a few years ago. Given the difficulty of storing and moving liquid hydrogen – and the danger of any potential escape – NASA required a method of accurately locating leaks. While sensors can detect the presence of hydrogen gas, pinpointing the exact piece of leaking infrastructure is more difficult. A team from the Kennedy Space Center worked with University of Central Florida to investigate the creation of a chemochromic sensor which would change colour when exposed to hydrogen. This could then be deployed via a tape matrix around key pieces of infrastructure such as pipe welds and seals. After two years of research, UCF researchers devised a pigment that could be added to a silicon caulk. According to a
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Day of the Hunter depths of the oceans in high fidelity.” Around five feet (1.5 metres) long, its head features stereoscopic vision to allow the pilot to see exactly what the robot is seeing, while the tail section houses batteries, computer systems and 8 multi-directional thrusters. Most important to OceanOne are its incredibly dextrous and sensor-rich hands. “Each fully articulated wrist is fitted with force sensors that relay haptic feedback to the pilot’s
controls, so the human can feel whether the robot is grasping something firm and heavy, or light and delicate. Eventually, each finger will be covered with tactile sensors,” Stanford explains. Although its first deployment has been on archaeological missions, we can imagine a day very soon where this kind of haptic robot will be able to carry out complex construction, repair and maintenance at subsea sites.
Microbots, roll out Max Planck researchers have developed selfpropelled tiny “microbots” that can remove lead or organic pollutions from contaminated water. Working with colleagues in Barcelona and Singapore, Samuel Sanchez’s group used graphene oxide to make their microscale motors, which are able to adsorb lead from industrial wastewater from a level of 1,000 parts per billion to down to below 50 parts per billion in just an hour. The lead can later be removed for recycling, and the micromotors can be used multiple times. In a statement, Sanchez – group leader at the Max-Planck Institute for Intelligent Systems in Stuttgart and the Institute for Bioengineering of Catalonia (IBEC) in Barcelona – explained: “The outer shell of the microbot, which is graphene, captures the lead. The inner layer of platinum works as the engine, decomposing hydrogen peroxide as fuel so that the bot can self-propel.” Between the layers of graphene oxide and platinum is a layer of nickel that allows researchers to control the movement and direction of the microbot magnetically from outside the container. The same principle is then used to gather all the microbots back after the adsorption is complete. “In the future, our microbot swarm could be controlled by an automated system that magnetically guides them to carry out various tasks,” Sanchez added.
The team also investigated microbots capable of collecting or degrading organic pollutants, and is now examining methods of mass production.
The US’ Defense Advanced Research Projects Agency (DARPA) has christened the first vessel under the Agency’s Anti-Submarine Warfare (ASW) Continuous Trail Unmanned Vessel (ACTUV) programme. According to DARPA, this is “an entirely new class of ocean-going vessel” and will autonomously patrol thousands of miles of sea without any crew aboard. Its potential missions include submarine tracking and counter-mining activities. Christened “Sea Hunter,” the vessel is a 130-foot (40-metre) twin-screw trimaran, designed to remain highly stable in all kinds of weather. Because it does not need to house crew, it can also carry a greater payload of sensors and equipment at a greatly reduced cost compared to manned ships. When desired, it can also be piloted remotely. Current development plans suggest the technology could be handed over to the US Navy as early as 2018. Given a few more years of qualification, it could have profound effects on automation in supply and even intervention vessels in the maritime and oil and gas industries. ©
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June page2016 15
Special supplement Pages 16-25
Redox revolution Interwell explores thermite P&A Page 21
The rig short
Tim Skelton examines rigless P&A Page 16
One-stop shop
Exceedâ&#x20AC;&#x2122;s decommissioning partnership Page 20
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June 2016
Rig-less is more Decommissioning
Tim Skelton reports on how rigless P&A techniques are bringing down the cost of decommissioning
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account for as much as 40-60% of the total ith more of the world’s spend on a decommissioning job. Operators offshore fields maturing, clearly need to find cheaper alternatives. many wells are reaching the end of their working lives. No rig or go home While standards and guidelines may change It is no surprise, then, that in its recent across borders – e.g. those set by OSPAR, Technology Outlook 2025 report, the ASCOPE, NOPSA to name a few – the Norway’s DNV GL cited rigless P&A as one endgame of plugging and abandoning those of the most important technologies in the wells (P&A) does not. Given the extent of oil and gas industry as it moves towards a the task involved, it is essential to carry out more automated future. DNV GL’s director these operations as efficiently as possible, of research and innovation, Pierre Sames, and to find ways of reducing the huge told a meeting in Houston in April that costs involved. Fortunately, here is where technologies would unfold over the next innovation can help. decade that “would take people off of the First, operators and innovators alike drill floor.” need to consider the scale of the problem. For many assets, platform wells especially, The North Sea, for example, is estimated to being able to carry out P&A without a rig contain as many as 8,000 wells which could will save money and time, he said. Scaled be taken out of service over the coming across a multiple-well abandonment decade, around 5,000 of which are in UK campaign, he added, “eliminating the need waters alone. The uncertainty of the process for a rig can potentially represent tens of is also a concern; in the UK, a 2015 study millions of dollars in savings.” carried out on behalf of the government’s Broadly, operators can make cost savings Department of Energy and Climate Change by reducing the turnaround (DECC) put the expected costs time for P&A by replacing of decommissioning all assets “Technologies jack-ups, workover in British waters at somewhere would unfold over costlier rigs and snubbing units. But between GBP40 and 70 billion the next decade purpose-built, more flexible (US$58-101 billion). Moreover, according to Oil & Gas UK that would take vessels also bring costs down the increased certainty figures, this estimate is rising at people off of the via they can offer. As DECC head a rate of about 14% per year. drill floor.” of offshore decommissioning Next is the issue of Audrey Banner remarked to equipment capability. Each Pierre Sames, individual well must be Director of Research and Offshore Engineer last year, the fluctuations in oil price permanently plugged and Innovation, and rig availability make secured to avoid the possibility DNV GL expenditure planning difficult. of future leaks before it “[Vessel/rig costs] could drop 30% or go can be considered decommissioned and up 20% depending on rates.” She pointed abandoned. Onshore, this has traditionally out that new techniques offered a sizable been a time-consuming task involving the prize, and that “Rigless abandonment could use of an expensive workover rig. Offshore, increase or decrease costs by about 50%.” vessel or platform rigs are typically used, and are necessary for more complex tasks, again Plugging pioneer adding to costs. One company that has played an early Even in a low-price market, that expense pioneering role on the rigless front is quickly adds up, and in many cases can NEWSBASE
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Claxton Engineering Services. Its P&A of Perenco Well A1 in the Leman field in 2003 was the first exercise of its kind in the North Sea, carried out without using a jack-up rig. While this required a fair degree of bespoke project planning and engineering, Claxton has since been involved in decommissioning more than 100 other North Sea platform wells, mostly without the need for a platform crane or drilling rig. Its Suspended Well Abandonment Tool (SWAT) system, for example, handles perforation, circulation and cementation of multiple casing annuli and can be deployed from a light construction vessel. Although some wells do still require a rig for P&A work, more and more are able
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MOSS V is a heavyduty jack up drilling rig, converted to a self-propelled vessel. Removing pre-existing drilling equipment from the top deck creates a 10,000-square-foot open deck serves for the accommodation of a number of different services. Pumps and tanks below deck are left in place, for potential use in P&A applications. to go rigless as the technology is fine-tuned and broadens the scope of what can be accomplished from floating vessels. This not only saves money and time, it also frees up more rigs for potentially more lucrative E&P activities. In the past, the biggest factors that have hindered rigless P&A have been logistical challenges such as a lack of on-board accommodation, the limited lifting capacity of platform cranes and limited deck space for working. Another complication has been that since the characteristics and specifications of each well are different – their depth, pressure and casing construction are all highly variable – the decommissioning of each
one must be dealt with individually. This uniqueness encourages much more bespoke engineering, and resists the trends for standardisation which has reduced costs in other sectors. That said, the capabilities of the technology – and the experience of personnel using it – are also increasing. Previously, rigless P&A operation were limited to category 1 wells (those which are plugged and abandoned and ready to pick up after cutting off the wellhead) and category 2 wells (which may require some slight intervention work, such as the removal of mud). But more specialist well intervention vessels (WIVs) are being refitted and commissioned, and are now able NEWSBASE
to deal with category 3 wells (which require well control, including the use of tubing). One such WIV will be the mobile offshore support services vessel MOSS V. Houston-based marine engineers William Jacob Management (WJM) recently won the contract for the detailed engineering and design for this concept ship, which is scheduled for completion in 2018 before being delivered to Northport Marine. MOSS V is a heavy-duty jack-up drilling rig that will be converted into a selfpropelled vessel. Although intended for use in several potential applications, one key role will be in rigless P&A. Refitting of the vessel will involve removing the pre-existing drilling equipment from the top deck, in
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Above: Claxton’s SWAT Tool
order to create a multi-use 1,000-square metre open utility space. Below-deck equipment, such as pumps and tanks, will be retained and used in P&A applications. As has been mentioned, typical jack-up rigs are only equipped with limited-capacity cranes. MOSS V will have a heavy-duty, 500-tonne capacity crane suited to dealing with almost any well. It is also designed to work in water depths of up to 125 metres, and will be large enough to withstand most severe weather conditions. Abandoning the future Major services providers are also taking these considerations on board. Houstonheadquartered Weatherford was named P&A Pioneer of the Year in February at the DecomWorld Decommissioning and Abandonment Summit in Houston, for its new “Rig-Free” light-duty pulling and jacking unit. Weatherford’s earlier heavy-duty rigless pulling and jacking unit has a hydraulically powered telescopic mast that sits directly above the well centre and has a 100-tonne pulling capacity. The new light-duty unit shares most of its older brother’s attributes and systems, such as power swivels and seamless changeover from mast-assisted to jacking operations. But being smaller and lighter enables it to handle many other abandonment tasks, especially in situations where space is at a premium or where platform structural strength is low. According to company specifications, the
Left: Equipment decommissioned by Offshore Installation Services (OIS)
unit can pull 13.6 tonnes and has a jacking capacity of over 450 tonnes. Encouragingly, the pace at which the industry is exploring new P&A avenues appears to be picking up. Some of this is incremental and structural – such as the repurposing of older rigs – but new innovation is breaking through too. With cost reductions remaining the driving impetus, this will likely involve making equipment smaller, lighter and more versatile whilst improving performance, as Weatherford’s global business unit manager for Well Abandonment, Ian Smith, notes. “Rigless abandonment units have to continuously develop in terms of increased specification such as torque and pulling capacity, whilst also reducing in weight and footprint,” Smith explained to InnovOil via email. “Improved and more efficient tubular NEWSBASE
handling equipment is required, which will improve safety and reduce crew size. Moreover, the ability to work on smaller satellite platforms will be important in increasing the well numbers that can be accessed either on the platform itself, or from a jack-up barge or other support vessel,” he added. It seems then that P&A technologies are being influenced by the same factors as the exploration and production phases. As a comparatively new sector, decommissioning looks set to reap very quickly the benefits of increased automation, lighter and more versatile vessels, and rigless intervention techniques which have taken the E&P sector years to implement. That willingness to innovate and experiment is vital, as gains made now, in P&A and elsewhere, could have profound implications for how the industry adapts in the coming decades. n
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Thermite makes P&A right Interwell is using thermite to melt rocks and seal wells, potentially transforming how the industry approaches P&A
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he need for new plug and abandonment (P&A) solutions has pushed operators to look increasingly outside the proverbial “box.” In the case of Norwegian well to plug the well. In addition, because the management firm Interwell, this has meant reaction produces its own source of oxygen, disintegrating the box itself. no external supply is needed and almost no In 2012 one of the company’s technical other gases are produced, making it a sound advisors for P&A, Michael Skjold, floated choice for use downhole. a radical new idea: using thermite to So far, so good – but a lot of this melt materials in the wellbore, forming was unproven. Given the novelty of the an impermeable barrier and sealing the technique, there was a severe lack of well. Given the company’s history in scientific study which could qualify any of shallow and deep-set well barriers, well the process. Interwell therefore brought in integrity and niche completion products, certification agency DNV GL this offered a wealth of new in 2013, to help investigate potential opportunities in the and ultimately qualify the decommissioning space. “Exothermic P&A Solution,” Primarily, Skjold says, (as it was initially referred to) the idea came in response to for commercial use. the need for cost reductions within P&A. As many Back to basics operators are exploring A lot of fundamental work options which dispense with was needed to underpin what the need for rigs, this method the team was attempting to could be deployed from a achieve. This meant studying single vessel with little external rock analogues, the processes equipment (the process would behind their formation and the also remove the need for resulting mineralogy and how cement or even coiled tubing). “When ignited, well molten materials might If successful, this could streamline the P&A process thermite burns at bond within these formations. In addition to funds from and potentially save significant around 2,500°C” the Research Council of time and money. Norway, in 2014 Statoil and BP The idea itself is remarkably were also brought in as partners in a joint simple. When ignited, thermite – a industry project (JIP), allowing the company compound of metal powder fuel and metal access to a wealth of information on wells oxide (most commonly iron oxide) – burns and formations in the companies’ databases, at around 2,500°C, enough to melt through in addition to their perspective as potential tubing, casing and cement. It is also hot clients. The same year also saw patents enough to melt the surrounding rock, granted on the technology. bonding the materials together and – in Alongside this, Interwell ran exhaustive theory – forming an ideal barrier with which NEWSBASE
tests to develop a system which could be deployed in the wellbore. In a video interview from 2014, Skjord explains: “The whole idea is to keep it as simple as possible. We want to make a manmade rock and to do this we want to enter the wellbore with a carrier device run on wireline. The carrier device will be placed on a wellbore annular heat shield, and activated to provide enough energy to convert all materials into an everlasting deep barrier that hopefully will bond to the surrounding materials.” Heating up Following the group’s 2014 feasibility certificate from DNV GL, they began scaled up testing of the tool. In 2015, they undertook onshore tests and small-scale subsea testing – crucial to determine whether the equipment would stand up to offshore conditions – before eventually building and testing a prototype in a specially designed test tank in Norway. This allowed Interwell to examine the system’s performance under simulated high-pressure, high-temperature (HPHT) conditions. The learning process also took the team to the Iceland Deep Drilling Project to study the behaviour of supercritical liquids – fluids above 347°C and at pressures greater than 220 bar – to support further tests of the P&A process in HPHT environments. With over 4 years of experience and 200 tests under its belt, the company is now heading towards field trials in onshore wells in Canada and aims to have 4 pilot wells completed by the end of the year. According
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Decommissioning The thermite melts the casing and surrounding rock, ensuring the plug bonds well to its surroundings
to a recent presentation, this would allow Interwell to commercialise the P&A tool fully for onshore and offshore during 2017, and for subsea operations in 2018. Although it has been a long road since the idea was first mooted, progress on the
tool has moved at a pretty rapid pace – in an update in late 2015 Skjold noted that the team was “thorough but in a hurry.” n InnovOil hopes to revisit the tool later in 2016, following the results of Interwell’s field trials. We will keep you posted on their progress.
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Exceeding expectations Having recently signed a new collaborative partnership with Weatherford for one-stop well decommissioning, Exceed’s John Anderson explained to InnovOil how this model could change the sector
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nlikely though it may seem now, John Anderson is already anticipating a North Sea rig shortage. For sure, it will not come immediately – but when it does, the decommissioning sector perhaps most of all will need some innovative technologies and flexible business models to fulfil its remit, while keeping costs down. Anderson, commercial director at well management firm Exceed, said that before the company entered the space the most important thing was to talk to as many operators as it could to determine what exactly it was that they wanted from a decom service provider. “Everyone said: a one-stop shop,” he explained to InnovOil. With core teams getting smaller and focusing on value-adding
work, he added, decommissioning is viewed as a removal of liability, meaning outsourcing is an attractive option from a technical and a commercial point of view. Although it has won contracts on its own – including supporting Fairfield Energy with its 61-well plug and abandonment (P&A) campaign – Exceed is now pairing its well management expertise with the technical knowledge of a number of other service providers to offer a flexible and collaborative decom model – with the aim of becoming that “one-stop shop.” Emergent technologies Accelerating the “learning curve” on decom techniques and technologies is one way the firm hopes to improve the process. “There are
an awful lot of ways to decommission wells, and thus far operators have tended – quite rightly – to use more proven methods, like section milling,” he noted. But this does not have to be the case; if emerging procedures can be proven to be reliable and adhere to regulatory guidelines – he stressed the flexibility they offer provided an operator can demonstrate their effectiveness – there is a lot of impetus to take them forward. This is where a future shortage of rigs will force a change. The expense of using an entire rig to perform only a few of its capabilities highlights the industry’s need to adopt more flexible options, either from platforms or from light intervention vessels. With new equipment Anderson believes future P&A campaigns in many cases could be done with “just a wireline unit and coiled tubing. Our partners offer a number of modular platform based packages, which will also help the partnership offer more flexible options to customers. He expressed excitement for other technologies too, in particular new acoustic and ultrasonic evaluation tools which help to enable engineers to see through multiple casing strings and improve the efficiency of plug placement and casing cuts and pulling. Likewise, he pointed to new perforation and circulating tools which will negate the need for more time-consuming section milling, helping to speed up the P&A process. “Wells are different – every application tends to be bespoke, so you need a wide range of tools… Because it’s decommissioning, everybody wants a tool which does more for less,” he said, “But it has to be proven.” Exceed appears willing to explore these new technological avenues as part of its contracts with a view to finding the best and most flexible approach – a flexibility which extends to procurement. “That was something we talked about on Day One. If there’s a better tool out there, we wanted [the freedom] to use it,” Anderson added. Role model Anderson also elaborated on the partnership model itself, and how collaboration might
Subsea tree removed as part of a rigless campaign NEWSBASE
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Decommissioning Exceed Commercial Director John Anderson
become more of a staple in the decom sector. The first point he raised was his belief that an incentivised approach works far better than a simple service/day rate, largely because “everyone buys in.” The industry has “never really been able to get away from adversarial contract terms,” he explained, but with all parties acting as stakeholders, there is far more room for co-operation and collaboration. “It tends to be what happens in the bad times, but it should really extend to the good times as well.” That collaboration should extend to operator procurement too. Currently, departments are “very siloed,” Anderson said, and will frequently approach one supplier for one component and another for something else. Part of the “one-stop” concept is to update
that idea – “We’re in a supermarket!” he says – and operators should be able to procure equipment through one invoice, rather than multiple. It is not a radical innovation, but it illustrates where savings can be made quickly and effectively as the sector grows. In the meantime, Exceed, and its partners will be taking the partnership model to the Gulf of Mexico, Middle East and East Asia. That model is also still evolving, and Anderson
hopes it will encompass even more in the coming years, to “wellhead, pipelines, subsea infrastructure – even platforms! It would be great to expand it into full-field.” For now, though, it seems like Exceed has plenty on its plate to kick-start some decom innovation. n Contact: John Anderson Tel: +44 (0) 1224 577 940 Email: info@xcd.com Web: www.xcd.com/
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Seeing infrared: LumaSense Technologies aids SRUs LumaSense’s Pulsar range aids sulphur recovery via continuous, instantaneous temperature measurement
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ydrogen sulphide (H2S) is nasty stuff. At all temperatures, it is corrosive to carbon steel and most engineering alloys and must be removed from finished petroleum products. To do so, the Claus Process takes place in a sulphur recovery unit (SRU) where H2S is converted into sulphur through thermal and catalytic treatment, before being used in fertilizers or as sulphuric acid in industrial chemical processes. That process requires very accurate temperature control, particularly in the reaction furnace, to prevent damage to the refractory at high temperatures and ammonium salt from plugging the converters at low temperatures. Given the high temperatures and corrosive nature of the process, this is a challenge for temperature instrumentation. Other installations which use reaction furnaces to incinerate waste gases such as ammonia or hydrocarbons must also maintain specific temperatures to assure their destruction. Advanced processes such as O2 enrichment normally require even higher temperatures and closer monitoring. Finger on the PULSAR The E2T PULSAR range from LumaSense Technologies is uniquely designed to measure two wavelengths for continuous and instantaneous measurement of refractory temperature (RT), gas temperature (GT) and integrated temperature (FF) in the vessel, away from the heat, vibration and corrosive gases of the furnace. Its custom mounting hardware also allows for visual inspection of combustion processes, refractory cure-out and preventative maintenance while the vessel is fully operational. Using two wavelengths makes it possible to apply a compensation calculation – the
through the Pulsar II and III and now the current generation E2T Pulsar 4. The latest model offers both simultaneous gas and refractory temperature measurement using a single thermometer installation, with data made available through separate 4-20mA or digital outputs. An even greater advantage is that the Pulsar 4 requires little-to-no-maintenance and eliminates the need to perform field calibrations when operating in FMA mode.
Flame Measurement Algorithm (FMA) – to remove the variable effects of flame transparency on the separate measurements. This FMA programme takes measurements from both the gas and refractory readings and compensates for changing flame transparency in real time, removing the inherent measurement errors of typical infrared thermometers and providing an accurate result. Process monitoring efficiency during sulphur recovery has been improved considerably over the product’s lifespan,
Change of HART Most recently, Pulsar 4 has been made fully compatible with the Highway Addressable Remote Transducer (HART) Protocol. This is the global standard for sending and receiving digital information across analogue wires between smart devices and control or monitoring systems. HART is a bi-directional communication protocol that provides data access between intelligent field instruments and host systems. This includes any software application from a technician’s hand-held device to a plant’s process control, asset management, or other any system using a control platform, ensuring operators have access to vital process information at any time. n Contact: Gerard Ames Tel: + 31 651 648 299 Email: info@lumasenseinc.com Web: www.lumasenseinc.com
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White graphene / white heat
Researchers from Rice University have used boron nitride to engineer lithium-ion batteries which work at far greater temperatures – and oil and gas technology could benefit
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esearchers at Texas’ Rice University have engineered a new electrolyte and separator for rechargeable lithium-ion batteries, allowing the cells to work across a far greater temperature range. Central to their innovation is the use of hexagonal boron nitride (h-BN), an atom-thin compound often referred to as “white graphene.” The resulting composite – which apparently resembles toothpaste – is used alongside conventional electrodes to improve the stability of the battery at high temperatures and voltages. The team’s paper, published in the Advanced Energy Materials journal in April, reports that the test battery remained stable for over 600 cycles at a temperature of 120°C, experiencing a capacity loss of 3%. Rice materials scientist Pulickel Ajayan stated in a press release that the battery continued to work from room temperature up to 150°C – one of the widest recorded envelopes for li-ion batteries. That is more remarkable when one considers that traditionally, storing a battery anywhere above 30°C is considered an “elevated” temperature. Most importantly, as the study’s lead author Rice graduate student Marco-Túlio Rodrigues told InnovOil, there are no commercial li-ion batteries on the market that can sustain temperatures above 80°C. “Even if they manage to avoid a complete failure
above this temperature,” he said, “They will not be able to perform nearly as well as they did under milder conditions.” Resistant, reliable Given that h-BN is chemically and mechanically resistant, even at very high temperatures, Rodrigues and the team believe that it could help offer increased stability to the battery’s electrolyte layer, helping it to function at higher temperatures. It possesses a number of desirable qualities for battery applications: it is not a conductor, nor known to be an ionic conductor, and is already used as a component in ceramics for high-temperature applications. Rodrigues explained: “It’s fairly inert, so it shouldn’t react with any chemicals, it won’t expand or contract a lot and the temperature isn’t a problem. That made it perfect.” Even more promisingly, tests showed that the mix of h-BN, a piperidinium-based ionic liquid and a lithium salt actually appeared to help catalyse a better reaction from the chemicals around them. Rice postdoctoral researcher and co-author Hemtej Gullapalli added: “Even though the boron nitride, which is a very simple formulation, is not expected to have any chemical reaction, it gives a positive contribution to the way the battery works. It actually makes the electrolyte more stable in situations when you have high temperature and high voltages combined.” What makes the team’s battery interesting NEWSBASE
is the fact that it not only survives at 150°C, but it works better under these conditions. In an email to InnovOil, Marco Rodrigues said: “Basically, once you can overcome the safety problems and the long-term stability of every single component of the battery, high temperatures actually help, accelerating the chemical reactions associated to energy storage in the cell, increasing the power output. Since our devices were optimised to withstand these harsh conditions, the performance will not degrade.” Yet that performance boost is a double-edged sword. Perhaps the greatest issue standing in the way of wider commercialisation of these cells is that an average room temperature is probably too low for the battery to operate in. Rodrigues conceded that “right now, due to intrinsic limitations on some of our components, our batteries do not work at their full capacity at room temperature and lower, reaching their peak beyond 50°C.” For now, that is a pretty major hurdle to overcome – and especially problematic when looking at deployment in EVs – but it does leave the technology very well suited to other applications. Separation innovation In conventional batteries, separators are made of plastics or polymers, which can melt or break down at higher temperatures. If that happens, or the separator is punctured, the
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Hemtej Gullapalli, standing, and graduate student Marco-Túlio Rodrigues at Rice University. (Picture: Jeff Fitlow/ Rice University)
battery will heat up and potentially ignite. Yet the construction of the Rice team’s battery prevents this from happening. That stability makes batteries inherently safer – a concern which has kept li-ion technology away from applications where they would otherwise be useful. Because the electrolyte’s components are non-flammable, “if there’s a failure, it’s not going to catch fire,” explained Gullapalli. Greater safety opens new doors for li-ion cells, as the paper’s abstract hints: “The ease of [the Rice team] formulation along with superior thermal and electrochemical stability of this system extends the use of Li-ion chemistries to applications beyond consumer electronics and electric vehicles.”
In his email, Rodrigues explained that while some might be used for oil and gas applications, they were still hindered by reach and safety. “MWD can be done nowadays by powering sensors with wirelines and, if the temperature is not too high, some specific types of non-rechargeable batteries,” he said. “The problems here are that wirelines have limited reach downhole and that both options can intrinsically provide only so much power. Having a remote power source that can operate at high power and even be recharged by harvesting units could allow information to be gathered at much longer timescales.” This would be possible by linking rechargeable batteries to conventional sources
Power for producers Industrial equipment and aerospace applications appear to be at the forefront of the team’s thinking. Rodrigues specifically noted the requirements of oil and gas drillers looking for robust batteries to power sensors on wellheads. “They put a lot of sensors around drill bits, which experience extreme temperatures,” he said. “It’s a real challenge to power these devices when they are thousands of feet downhole.” Currently, many industrial devices which do use batteries use non-rechargeable cells, posing issues with disposal and the fact that they require a complete pack change between discharges. NEWSBASE
– e.g. mud pulse turbines – allowing them to use and store energy would otherwise be wasted. As Rodrigues alludes to, this opens up the possibility of much longer operating periods for some equipment, and slashes the need to retrieve, recharge and re-deploy. While the Rice team’s battery is unlikely to be suitable for applications at the very extremes of production, a 150°C operating threshold does carry it into high temperature (HT) territory – an area which is crying out for greater innovation around powering equipment. For ever more cost-conscious operators, Rodrigues was confident that while these batteries would be more expensive than conventional li-ions, they would not be prohibitive. He added: “Our concept was developed towards specialty batteries, able to power under conditions so far impossible to be tackled by current technologies.” So, although the final product may potentially be more expensive, “the benefits generated by operations lacking remote powering capability would overcome the additional costs.” However the technology is commercialised, it looks promising enough to take li-ion technology into realms it has never been before. With the 80°C goal already surpassed, Ajayan said that the team’s next step would be “to break this barrier and create stable batteries at twice this temperature limit or more.” n
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Energy industries face up to cyber security risk Martin Clark reports on a recent panel hosted by IT billionaire Eugene Kaspersky, who believes that energy firms must up their game if they are to combat the increasingly sophisticated threat of cyber terrorism
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solution specifically aimed at industrial ecent events have shown that systems. energy companies and their critical In a world where IT and process installations – everything from oil automation systems are integral to modern rigs to micro grids – can no longer industrial facilities, including power ignore the threat of cyber attack. That was plants and refineries, safeguarding these the message from Eugene Kaspersky, the processes is absolutely vital to their smooth Russian billionaire founder of Kaspersky operation. But unlike traditional corporate Labs, one of the world’s top producers of IT networks, where confidentiality is the top anti-virus software systems. priority, industrial control systems demand It is a threat that originates from multiple faultless continuity and consistency. sources: from highly sophisticated and wellfunded criminal gangs to state-sponsored Threat detectives attacks and terror groups. Motivations In many cases, a threat emerges where also vary from national interests down to systems and equipment have ransomware, designed to get not kept pace with the rapid a victim to pay a ransom fee advance of technological to the malware operators. change and the internet. At a recent panel on “An increasing number cyber security and energy, of systems are using devices Kaspersky noted that the and channels that interact oil and gas industry and with the outside world,” the electricity networks are said Kaspersky. “Sometimes both particularly vulnerable. they use equipment that was Attacks by a group calling never intended for external itself Dragonfly in in 2014, access, not to mention last year’s hacks which shut software that was created down parts of the Ukraine “Not only is the decades ago and has not been power grid and the highprofile 2011 virus that continuity of the upgraded since. This is a very serious issue, because not wreaked havoc on Saudi production process only is the continuity of the Aramco’s computer network at stake; the production process at stake; all illustrate the possible consequences. Although in environment and the environment and even human lives can be at risk.” the case of the latter the virus even human lives The issue of outdated did not affect oil production, can be at risk.” security is especially acute it was deemed the first in regions where production significant use of malware in Eugene Kaspersky is being extended. As DNV a so-called “hacktivist” attack, GL noted in a recent energy cyber security and served as a major wake-up call to the report, the average 15-20 year lifespan of industry. a Norwegian offshore installation means Kaspersky’s warning is of course a new that many will operate through several opportunity for cyber security firms too; his generations of technology. With low oil company is launching a new cyber security NEWSBASE
prices increasing the prevalence of life extension programmes, the threat of vulnerability becomes even greater. Yet sometimes it is these outdated structures that can also lead to a solution. In the recent example in Ukraine – where hackers gained entry to systems controlling electrical substations and plunged parts of the country into blackouts – Kaspersky said the crisis was resolved after resorting to a manual override option that had been built into the system. In more sophisticated power infrastructure set ups, such as in the US or Western Europe, there is typically no such facility. What is more, the sheer complexity of modern day industrial IT systems means that solutions which can guard against such
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Saudi Aramco needed an army of IT technicians to repair damage done to its IT systems in 2011
attacks are unlikely to be easy to deploy – or cheap. “It’s not a product to deploy; it’s a project,” Kaspersky said. Another speaker at the press conference, SolutionsPT industrial control systems security expert Cevn Vibert – who has worked on projects with EDF, Sellafield, RWE, National Grid, BP, KOC and Royal Dutch Shell among others – agreed. “Due to the complexity of the systems, and the complexity of the attacks, this can’t be done overnight,” he said. Industry awareness But understanding of these threats has
increased in recent years, experts reckon. Certainly, the Aramco attack five years ago helped focus minds among oil and gas executives. “After the Saudi attack, cyber security is one of the top priorities for oil and gas companies,” Kaspersky noted. Indeed, he attended a dedicated oil and gas stream himself at the World Economic Forum in Davos to discuss cyber security issues. “Don’t worry about the oil and gas industry,” he assured the panel – “They are aware of the problem.” Greater awareness has meant the problem is also becoming better understood across the board. “Years ago I had to explain NEWSBASE
industrial security, but not anymore. Now people understand. The situation is much better than years ago, though it’s still early days,” he said. Indeed, he noted that Russia had just launched a new cyber security training facility specifically to help the oil and gas industry counter the threat. Oil engineers are now invited to the Moscow site to develop a greater awareness and understanding of the risks and how to face them. Even where some countries, such as the UK, are acutely aware of the cyber problem – companies like National Grid are exploring extra resilience measures on an ongoing basis – implementing those protective measures is an altogether different challenge from a practical perspective. The threat to electricity distribution was specifically highlighted following the UK’s
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rollout of 27 million smart meters to every home across the country. Because these are essentially connected to an external network there is an inherent threat – something Vibist posited when he asked: “Smart meters: should we be concerned about it? Yes – but there is a lot of work going into that.” These devices could potentially be used for ransomware, where an attacker shuts down domestic systems demanding money. “It’s not science fiction because it’s happening,” Kaspersky commented. “To hijack a smart house and ask for a ransom, why not? Sometimes it’s very hard to trace [the perpetrators].” Cultural shift Funding such large IT security projects represents another hurdle, of course. Surprisingly, Kaspersky noted that there was still money in the bank to fund cyber security work, even at a time when budgets are being cut. While general IT infrastructure work may have been frozen, cyber security initiatives are still moving forward – in no small part thanks to the Aramco attack, which continues to serve as a major warning to oil firms. The scale and complexity of the problem remain a huge challenge, however. “It’s not easy, and it’s not cheap, and we don’t have enough engineers – but we
need to do it,” Kaspersky said. An important step forward is making sure any installation knows whether it has been hacked in the first place, Kasperky said. This is not always straightforward. In some larger facilities or organisations, the culture may be one where different departments do not communicate at all. Kaspersky believes that state governments should take more responsibility for critical infrastructure, to help educate industries and collectively design common cyber strategies. The lack of regulation in this area – essentially companies design their cyber systems any way they want to – may be another
area where governments could take the lead. This was again echoed in DNV’s energyfocused report, which stated: “Supervisory authorities should issue functional requirements stipulating that barriers to digital vulnerabilities must be established. Digital vulnerabilities must be included in relevant risk analysis.” “Companies must create a culture for reducing digital vulnerabilities in the same way as there is a culture for preventing fires and explosions,” it added. It is fair to say that this cultural shift is beginning, but as each new technological advance brings its own new set of threats and vulnerabilities, energy firms will need to work harder than ever before to stay one step ahead. n
Aramco and the Cutting Sword of Justice In August 2012, hackers gained entry to Saudi Aramco’s internal IT network and wreaked havoc, shutting down around 30,000 workstations in a matter of hours – about 75% of the company’s IT infrastructure. Timed to coincide with Ramadan when much of the company was on holiday, this was a co-ordinated attack by a group which called itself “Cutting Sword of Justice,” and which used a variant of the now-infamous Shamoon virus. The virus erased files and wiped entire computers, leaving them unbootable. The destruction of files and equipment is a notable tactical difference compared to other malware attacks, which traditionally seek
Saudi Aramco’s office buildings in Dhahran city
to remain undetected, enabling the hackers to view and/or steal data – although reportedly the hackers did have the ability to extract information from the files. The virus spread internally around Aramco’s global headquarters, leaving engineers pulling Ethernet cables out of
machines to disconnect them from the internet. With only internal mail and typewritten paperwork – digital payments, invoicing and contracts were all compromised – Aramco’s offices were catapulted back in time to the 1970s. Unable to sell oil to domestic fuel suppliers, it
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eventually began giving away oil for free to ensure local supplies. The clean-up operation was equally substantial. Aramco pulled in an army of IT contractors from around the world to secure and reboot its offices over a period of around five months. It also went directly to component manufacturers in Southeast Asia and, in one move, bought an entire line of replacement hard drives. The 50,000-unit purchase was made at a premium to overtake all existing orders, and raised global prices for the component for the next six months. As far as has been made public, the hackers were never caught.
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Innovation key to Statoil’s cost cutting
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Statoil is to capitalise on technological advances and additional resources to prolong the lifespan of its Asgard A production platform in the Norwegian Sea by an extra five years.
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ompany director Torje Saur said a study of the technical conditions at Asgard had proved that modification works could continue offshore, eliminating the need to transport equipment ashore. Asgard A will now operate until 2030 to capitalise on what Saur said were sufficient resources to make the scheme effective. The state-run Norwegian company wants to maintain current output at Asgard which, according to the firm’s production figures for the 2015 fourth quarter, totalled 37,600 barrels per day in liquids plus 61,900 barrels of oil equivalent per day of natural gas. Statoil operates Asgard with a 34.57% stake alongside partners Petoro (35.69%), Eni Norge (14.82%), Total (7.68%) and ExxonMobil (7.24%). Asgard is located on the Haltenbank, 200 km from the Norwegian coast and 50 km south of Statoil’s Heidrun field. The area contains three main deposits – Midgard, Smorbukk and Smorbukk South – dating from the 1980s, but Statoil has had some success in uncovering additional resources for Asgard in recent years. In August 2013, Statoil made a gas and condensate discovery in the Garn formation at the Smorbukk North prospect with a preliminary estimate range of between 25 million and 47 million boe. Statoil then managed to revive development at the potential Trestakk tieback in PL091, which was previously suspended because of low crude prices, after reducing initial development costs by around 30%. Forsys Subsea is contracted to deliver a front-end engineering design (FEED) study for Trestakk, which is believed to hold around 50 million barrels of oil plus 1.7 million cubic metres of gas. A final decision on the plan, which would involve tying five wells to Asgard A, is due later this year. Statoil launched the world’s first subsea gas compression facility at Asgard in
September 2015, bolstering recovery rates from the Midgard reservoir from 67% to 87%, and from 59% to 84% at the Mikkel reservoir. The technology should add 306 million boe to the area’s recoverable reserves, extending the two reservoirs’ productive lifespans until 2032. Aasta Hansteen Elsewhere, Statoil is scouring the market for savings at its Aasta Hansteen gas field development. The project’s previous launch date of the fourth quarter of 2017 has now slipped to 2018 owing to engineering construction delays at Hyundai Heavy Industries’ shipyard in South Korea. Delays at the 32 billion kroner (US$3.85 billion) development are forecast to increase Statoil’s costs at Aasta Hansteen by around 9%. Reports on April 5 suggested Statoil would seek a new drilling rig to undertake a seven-well programme at Aasta Hansteen to capitalise on the expiry of NADL’s West Hercules charter in January 2017. Statoil spokesperson Ola Anders Skauby said the company had registered a market inquiry to ascertain how much a deepwater drilling rig on the Norwegian Continental Shelf (NCS) might cost from late-2017. NEWSBASE
Statoil needs to reduce costs to ensure that its debt-load remains under control. Forecasts from Moody’s last month projected the company’s debt-to-EBITDA ratio could spiral to 2.0 in 2016-17 from 1.3 last year if Brent trades at an average of US$33 and US$38 per barrel in 2016 and 2017 respectively. West Hercules was originally contracted to Statoil in 2012 at a day rate of US$497,000, but drilling rig prices have declined sharply thanks to plummeting utilisation rates caused by the industry depression. Research from IHS indicates that the average day rate for semi-submersibles worldwide dipped to just over US$300,000 in December 2015, as utilisation rates drifted towards 50%. Each well at Aasta Hansteen is thought to take between 60 and 70 days to complete, which suggests that a semi-submersible at December 2015 day rates could cost Statoil between US$126 million and US$147 million. Assuming West Hercules was set to work under its original charter rate, costs would have amounted to between US$209 million and US$244 million under the previous plan, meaning Statoil stands to save around 40% by hiring a new rig.. n
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Mesotech transducer finds new life through a lens Kongsberg subsidiary Mesotech has developed a unique design to tackle the problem of sonar beam defocusing, producing more accurate and detailed results
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hile sonar has been used on ROVs for over 30 years, improvements in technology have led to major advances in accuracy, depth rating and resolution. Yet despite those advancements, the basic transducer design has not been altered much since the mid 1990s. Early designs used fixed frequencies and exposed the transducer to the sea water. However, this also left other crucial components exposed, and any failure of the protective o-ring seals could result in damage to the equipment. To combat this, in the 1990s designers housed the transducer in an oilfilled dome, providing protection from water but preventing more accurate results. Doing so, however, introduced a new problem. The difference in temperature between the oil and the surrounding water led to defocusing of the sonar beam in warmer shallower water, and in deeper, colder water. This defocusing becomes more extreme as water depth increases – an acute problem as firms increasingly take ROVs and other equipment to these environments. Despite improvements in the technology – variable-frequency wide-band units now provide greatly improved resolution, range and can produce wider beam widths – the ultimate accuracy is limited by the oil-filled dome. Speed of sound Konsgberg Mesotech is the Canadian subsidiary of the Norwegian-headquartered maritime firm, and specialises in sonar other and acoustic instrumentation and equipment. Noting the problem of beam defocusing, the
Beam pattern comparison At 40˚C, with the lens At 40˚C, without the lens
firm’s engineers set about investigating ways to correct it. The issue arises from the fact that the acoustic properties of oil are very different from those of seawater. In seawater, rises in pressure, depth or the salinity of seawater will increase the velocity of sound – yet these velocities do not change inside the dome. As a result, the two velocities only converge at a water depth of around 500m, before deviating significantly. A sound wave will also refract as it passes from one medium to another – as measured according to Snell’s Law. This means that as the transducer signal passes out of the oil and into water (and then vice versa when it is received), the beam will refract, causing the signal to be defocused. This produces blurred results. Refraction also intensifies with depth, meaning defocusing will be worse the deeper the ROV dives. Mesotech’s solution to this is refreshingly NEWSBASE
vanalogue. Designers fixed a water-filled acoustic lens on top of the transducer and inside the dome which corrects the refraction of the beam – working in much the same manner as an optical contact lens. The result, it claims, is a reduction in beam width and significant improvements in resolution and usable operating range – illustrated here in the beam pattern graph. That increased image quality is of major benefit to operators pushing further into deepwater, especially in application environments with poor visibility. The technology will be rolled out later this year, beginning with the company’s 171 4,000m lightweight domed sonar model.n Contact: Daryl Morse, International Sales Manager – Underwater Vehicle Instruments Email: km.sales.vancouver@km.kongsberg.com Web: www.km.kongsberg.com/mesotech
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BP awards Miller decom contract to Petrofac PETROFAC will undertake late-life duty holder responsibilities for BP at the Miller platform in the Central UK North Sea for an undisclosed sum. The services company will manage all onshore and offshore work related to the transition at Miller, preparing for the next phase of decommissioning. Although the contract term is stated as “life of asset”, BP has stipulated a four-year limit, after which extension options will be considered as required. BP remains the licence holder at Miller. Miller is located in Blocks 16/7b and 16/8b, 270 km northeast off Aberdeen. The field was discovered in 1982 in acreage awarded to BP under the seventh UK licensing round, with oil resources located 4,000 metres below the seabed.
Miller reached peak production of 150,000 barrels per day from a 12-slot drilling template. Had BP chosen to proceed with a US$1 billion scheme to provide carbon capture storage (CCS) at Miller in 2007, the project could have recorded a 21st Century industry first. Despite two postponements aimed at securing UK government funding, which arrived too late for a viable investment, BP halted production at Miller in July 2007. BP has already undertaken well abandonment and topside clean-up operations at Miller, and anticipates full removal of the topsides in 2017-18. Three pipelines serving Miller are to be left in situ under the UK’s disused pipeline regulations, allowing BP to propose alternative usage within a ten-year period. Miller was served by an 18-inch (457-mm) oil export pipeline sending crude for processing at the Brae A platform, and a 30-inch (762-mm) gas export pipeline to the St Fergus processing terminal. There was also a 16-inch (406-mm) two-sided link between Miller and the Brae B platform, capable of sending gas from both projects in either direction.
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Miller is one of a number of UK Continental Shelf (UKCS) projects scheduled for decommissioning in the coming years. Also on the slate are the Murchison field in Block 211/19a and Brent in Block 211/19. Decommissioning spending topped GBP1 billion (US$1.45 billion) in 2014, the highest figure on record and equivalent to 4% of total UKCS investment. Edited by Ryan Stevenson ryans@newsbase.com
Majors adopt joint approach to equipment production Ten global oil companies including BP, Royal Dutch Shell, Total, Eni, Engie and Statoil are to collaborate to produce standardised production equipment to help drive down costs. The so-called Standardisation of Equipment Specifications for Procurement initiative could save the companies involved billions of dollars, according to Harry Brekelmans, projects and technology director at Shell. Items that could be mass produced at a lower cost under its auspices include bespoke valves, paints and underwater equipment, he said last week, adding that the companies also want to set up institutions to fund future savings. “We’re coming together with a number of other operators and suppliers to focus on standardisation and common requirements and pushing it all the way into how we can create common inventory,” Brekelmans said. Inefficiencies stemming from energy companies’ desire to protect patents for parts as basic as bolts or ladders have pushed up industry costs for years – an issue that has become critical for many as the start of the global crude price rout approaches its second anniversary. Achieving greater standardisation should also benefit oil companies even after oil prices have recovered. It remains to be seen, though, how well energy companies will collaborate in practice, especially as crude prices inch upwards, cost pressures ease and business-as-usual competition resumes. “It is still too early to say whether the push for standardisation is working,” said Jon Clark, oil and gas advisor at consultancy EY. “While this is an industry that prides itself for its technology, it has not always been able to work
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together to lower costs, even as companies try to adjust to the lower price environment.” One take-away from last week’s Offshore Technology Conference 2016 in Houston was also that operators across the world view equipment standardisation as key to improving field economics. However, “what is becoming increasingly evident is that most cost reductions and solutions proposed thus far only take a haircut to costs and are temporary in nature [ie service costs] thus not transformational,” with many offshore operators continuing to hold out on standardisation, joint ventures and other steps, Raymond James & Associates energy analyst J Marshall Adkins wrote in a summary of the event. “That said, the willingness of most companies to take these incremental changes has increased as the downturn has persisted and this industry has historically been very good at adapting to changing conditions,” he noted. Edited by Ryan Stevenson ryans@newsbase.com
The workshop invited speakers who had expert knowledge in the field of subsea storage tanks, who brought the audience up to speed with the state of the art and the issues arising. In the afternoon the delegates debated the way forward for subsea storage in tables under the themes, concept selection, construction, and operations. A host of issues and solutions were identified. NSRI are at present documenting this and identifying the technology gaps which it will highlight to industry as developmental opportunities. Presentations from the event are available here. NSRI
Schlumberger ditches Fortuna FLNG plan
Gordon Drummond, project director of NSRI
NSRI tackles subsea storage On April 21, National Subsea Research Institute (NSRI) held the first of its focused workshops addressing some of the potential solutions that had been identified through the previous hackathon events. Subsea storage has been used in the O&G environment for many years, but has not enjoyed widespread acceptance. In fact, there are only two or three tanks in use on the UKCS.
Schlumberger has dropped out of a plan to participate in the construction of a floating LNG (FLNG) plant offshore Equatorial Guinea. Ophir Energy announced the service company’s withdrawal on April 29, saying that plans were moving ahead regardless and that costs were falling. However, a final investment decision (FID) on Fortuna has now been pushed back to the fourth quarter of the year, with first gas targeted for early 2020. In January, Ophir said it would reach FID by mid-year, with first gas in 2019. Schlumberger signed on to the Fortuna FLNG scheme in January this year, under a non-binding heads of terms. Ophir said the companies had been unable to complete the transaction on the terms agreed and, as a result, talks had ended. Ophir said that the project remained “technically and financially attractive” and that there were a number of alternatives to Schlumberger. The company went on to say talks were continuing with other parties, on various topics including equity participation, vendor financing and pre-sales of gas. Offtakers have been narrowed down to NEWSBASE
three options, it said. Following completion of the front-end engineering and design (FEED), bids were submitted, with costs reduced from US$600 million to US$450-500 million gross. The development and production plan was submitted to Equatorial Guinea’s Ministry of Mines, Industry and Energy (MMIE) in March. “The reduction in the capex to first gas has lowered the project breakeven oil price to approximately US$40 per barrel,” said Ophir’s CEO, Nick Cooper. “We continue to work closely with Golar, the prospective offtakers and the other potential partners and remain confident that we will take the FID in 2016.” Schlumberger had been due to acquire a 40% economic stake in the FLNG project, with a commitment to reimbursing 50% of Ophir’s past costs. This would have covered Ophir’s share of spending to first LNG sales, it said at the time. The service company had also signed a memorandum of understanding (MoU) with Golar LNG, focusing on developing gas reserves and FLNG. The deal, signed at the same time as the Ophir heads of terms, was to provide access to “a wide range of uneconomic gas reserves by delivering low-cost LNG production solutions”, Golar said, describing it as ground-breaking. The two companies working together will be able to provide an integrated package, which will reduce risk and secure financing for gas projects. Its main aim will be to accelerate the time it takes to bring gas reserves into production. Edited by Ed Reed edreed@newsbase.com
Shell deals blow to Norway’s Arctic ambitions Royal Dutch Shell has announced plans to withdraw its application for Barents Sea acreage that it applied for in Norway’s 23rd licensing round.
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News in brief Baretnts Sea, Picture: NASA
Oslo offered 52 Barents Sea exploration blocks in December 2015, with 34 of the licences located in the southeast Barents. The area was previously inaccessible owing to territorial disputes with Russia. The Norwegian Petroleum Directorate (NPD) received bids from 26 applicants and is forecast to announce the results later this year to allow drilling to commence in 2017. Shell lodged several applications for licences in the southeast Barents, stressing its experience with working in Arctic conditions after campaigns in Alaska, Russia and Greenland. But on April 4, Shell’s head of oil and gas production, Andy Brown, noted that the company had already committed to exploration cutbacks in frontier regions following its US$50 billion takeover of BG Group on February 15. Furthermore, Shell has already suffered setbacks in its campaigns elsewhere in the Arctic, having cancelled its Alaskan efforts in September 2015 after a US$7 billion exploration campaign failed to produce any tangible results. The Anglo-Dutch super-major has set a US$33 billion capital expenditure target for this year, US$4 billion higher than its final 2015 forecast, but US$2 billion lower than
previous projections for 2016. Research by Bernstein cited by the Wall Street Journal suggests Shell could cut expenditure further to US$28 billion with cost reductions, project delays and reduced exploration expenditure. In this context, Shell is likely to have concluded that it should avoid straining its cash flow with extra exploration obligations in a region where profitability remains unproven at current oil prices. Arctic exploration has struggled in recent years as companies have become increasingly wary of the high costs of production and technical challenges that affect projects in the world’s northernmost reaches. Oslo had high hopes for Arctic development after Statoil launched its Snohvit gas field in the Barents Sea in October 2007, but the pace of exploration has slowed with the collapse in crude prices. Statoil was one of the major applicants in Norway’s latest licence round. Its senior vice president Jez Averty dismissed speculation that resources in the Barents would prove noncommercial. Edited by Ryan Stevenson ryans@newsbase.com
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Woodside seeks low-cost exploration opportunities Australia ’s Woodside Petroleum has taken a cautious stance in terms of committing to large scale LNG projects but has kept an eye on potential upstream investments in Africa. In particular, the company is taking advantage of low service prices to acquire seismic in new frontiers. Speaking during Woodside’s AGM in April, the company’s chairman, Michael Chaney, noted the agreement with Impact Oil & Gas from February. Woodside struck a deal to acquire a 65% stake in the production-sharing contract (PSC) and joint operating agreement (JOA) on the AGC Profond block. The block is in the joint development area between Senegal and Guinea Bissau. The deal was an example of Woodside’s exploration strategy, Chaney said, describing it as “a very prospective area” with the move building
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on “our other recent acreage acquisitions in Cameroon, Gabon and Morocco”. The block covers 6,700 square km, in water depths ranging from 1,400 metres to 3,700 metres. Completion of the deal remains subject to meeting a number of conditions. The AGC Profond is in its first exploration stage, with a work obligation covering seismic licencing, reprocessing and studies, Woodside said. The Australian company is also working in the Rabat Ultra Deep Offshore reconnaissance licence. During the first quarter, processing of 1,074 km of new 2-D seismic was completed, it said. This will be used to determine plans for further work. Edited by Ed Reed edreed@newsbase.com
MOL launches new LNG transport project in Indonesia JAPAN’S Mitsui OSK Lines (MOL) and its partners have inaugurated a new coastal LNG transport project in Indonesia. The Triputra, an LNG carrier with a tank capacity of about 23,000 cubic metres, transported a cargo from the Bontang LNG plant in East Kalimantan to a newly built small-scale LNG receiving terminal at the Port of Benoa on Bali Island for the first time, MOL said on May 6. The Triputra is owned jointly by MOL, GTS Internasional, PPT Energy Trading and LNG Japan. GTS Internasional is a wholly owned
subsidiary of Indonesia’s Humpuss Group, while PPT Energy Trading is a Japanese subsidiary of Indonesia’s state-owned Pertamina. The Triputra will transport between 200,000 and 300,000 tonnes per year of LNG from the Bontang plant to the Benoa LNG receiving terminal under a seven-year contract with Pelindo Energi Logistik (PEL), a subsidiary of Indonesia’s state-owned port operator, PT Pelindo III. The LNG will be regasified at the Benoa LNG receiving terminal, which is owned jointly by Pertamina Gas (Pertagas) and Pelindo III. Pertagas is a subsidiary of Pertamina. The Benoa LNG receiving terminal consists of a floating storage unit (FSU) and a floating regasification unit (FRU). This is MOL’s second coastal LNG transportation project in Indonesia. In 2011, MOL and its Indonesian partner, Trada Maritime, won an LNG transport contract from Nusantara Regas for the West Java LNG receiving terminal. Nusantara Regas is a joint venture between Pertamina and Indonesia’s state-run gas distributor, Perusahaan Gas Negara (PGN). Indonesia is largely known in the LNG world as a major exporter. However, in order to meet growing domestic demand for natural gas, it intends to construct a number of receiving and regasification terminals. The country’s Arun LNG plant, in Aceh, has been repurposed from serving as an export plant to be Indonesia’s third – and first land-based – LNG receiving and regasification terminal. Perta Arun Gas, a subsidiary of Pertagas, is the operator of the Arun LNG terminal Edited by Andrew Kemp andrew.kemp@newsbase.com
Forum Energy Technologies delivers 9 subsea PLR systems Forum Energy Technologies Inc. has successfully delivered a number of its largest subsea Pig Launchers and Receivers (PLRs) and laydown heads to a project in North Africa. The nine PLRs have been deployed as part of a development of nine subsea wells, which vary from four to 24 inches in size, with water depths ranging from 300 to 800 metres. The custom-designed units will be used in the completion of flooding, cleaning, gauging, strength test, intelligent pigging and dewatering activities. John Thompson, operations director at the company’s Moffat site, said that: “The scope of work for the project, which included the full design, manufacture and testing of the PLRs, underlines the fully integrated system we can offer from concept through to delivery.” In addition to their size and weight, Forum’s PLRs have other additional capabilities compared with conventional systems because they are also equipped with a remotely operated vehicle (ROV) readable subsea flow meter, a ROV operable choke valve for discharge throttling to control the pigging velocity. Forum also developed and manufactured a landing interface from the PLR’s to the pipeline end terminator (PLET) with a horizontal driverless connection system. FORUM ENERGY TECHNOLOGIES
ExxonMobil, FuelCell Energy tackle carbon capture technology ExxonMobil and FuelCell Energy are to pursue new technology in power plant CO2 capture, through a new application of carbonate fuel cells. The hope is that the technology could substantially reduce costs and lead to more economical large-scale applications. Vijay Swarup, vice president for research and development at ExxonMobil Research & Engineering Company said that: “Our scientists saw the potential for this exciting technology for use at natural gas power plants to enhance
The Surya Satsuma, befor it changed its name to The Triputra
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potential breakthrough comes from an increase in electrical output using the fuel cells, which generate power, compared to a nearly equivalent decrease in electricity using conventional technology. The resulting net benefit has the potential to substantially reduce costs associated with carbon capture for natural gas-fired power generation, compared to the expected costs associated with conventional separation technology. A key component of the research will be to validate initial projected savings of up to one-third. The scope of the agreement between ExxonMobil and FuelCell Energy will focus, for about one to two years, on how to further increase efficiency in separating and concentrating CO2 from the exhaust of natural gas-fueled power turbines. Depending on reaching several milestones, the second phase will more comprehensively test the technology for another one to two years in a small-scale pilot project prior to integration at a larger-scale pilot facility. ExxonMobil
KS Drilling postpones delivery of Chinese-built jack-up
the viability of carbon capture and sequestration while at the same time generating additional electricity. We sought the industry leaders in carbonate fuel-cell technology to test its application in pilot stages to help confirm what our researchers saw in the lab over the last two years.” Chip Bottone, president and chief executive officer of FuelCell Energy, Inc., said his company is pleased to bring its global leadership in the development of carbonate fuel cells to this
project. “The carbon capture configuration has the added benefit of eliminating approximately 70% of the smog-producing nitrogen oxide generated by the combustion process of these large-scale power plants.” Two years of laboratory tests have demonstrated that the unique integration of two existing technologies – carbonate fuel cells and natural gas-fired power generation – captures CO2 more efficiently than existing scrubber conventional capture technology. The NEWSBASE
DELIVERY of a Chinese shipyard-built large jack-up drilling rig capable of accommodating 150 people has been delayed for 18 months at the request of the buyer because of the offshore industry slump. It is the second postponement by Singapore’s KS Drilling. The rig, KS Orient Star, was originally scheduled to be handed over by Cosco Nantong in 2014 before being pushed back until April this year. Now Cosco has agreed to retain the finished rig until December 2017, shipping industry magazine Splash 24/7 has said. “In the spirit of partnership between KS Drilling and Cosco Shipyard, and in light of the currently unfavourable oil and gas market climate... KS Drilling and Cosco Shipyard have agreed to extend the time for KS Drilling to take delivery,” the Singapore company said. The rig is one of two originally ordered by KS Drilling. The first was taken by the buyer in 2014. Splash 24/7 said the two companies
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had agreed that Cosco could sell the jack-up rig if the price covered both parties’ costs. State-owned Cosco operates yards in several ports. Reports emerged in April that subsidiary Cosco Guangdong was facing financial difficulties owing to a lack of new orders and was seeking to lay off workers. The central government is encouraging state yards to merge and consolidate, and Cosco in April was reported to be in talks on a shipyard joint venture with Kawasaki Heavy Industry of Japan involving the amalgamation of two yards in Dalian. Meanwhile, a subsidiary of China State Shipbuilding Corp. (CSSC) is continuing to expand its fleet of very large crude carriers (VLCCs). CSSC Shipping has emerged as the secret buyer of the US$25 million secondhand VLCC sold by Germany’s DS Tanker at the beginning of this month, Splash 24/7 has reported. The Chinese shipper now has five VLCCs and is rumoured to be the buyer of a sixth second-hand crude carrier, sold by John Fredriksen’s Ship Finance International last week also for about US$25 million. Edited by Andrew Kemp andrew.kemp@newsbase.com
NextDecade files LNG terminal, pipeline project application TEXAS-BASED NextDecade has filed its application with the US Federal Energy Regulatory Commission (FERC) to build and operate its proposed Rio Grande LNG project. The US$20 billion, 27 million tonne per year LNG terminal would be located at the Port of Brownsville in Texas. The FERC application also includes a 137-mile (220-km) pipeline system from the Agua Dulce Hub that will supply gas to the facility. NextDecade said it was now “in an excellent position to sign offtake agreements and declare final investment decision [FID] in 2017” for the project. “Despite recent low oil and gas prices, we have found robust appetite for US LNG on a long-term basis all around the world,” said NextDecade’s CEO, Kathleen Eisbrenner. “This interest reaffirms the price competitiveness of US LNG for customers looking to diversify their gas supply on a global level.” The San Antonio Business Journal reported that NextDecade had already signed non-
binding agreements to deliver 26 tonnes per year of LNG to customers globally. In its application, NextDecade asked regulators for permission to use gas from the Eagle Ford shale in South Texas as feedstock for the export project. According to the FERC filing, the terminal would include six liquefaction trains with a nominal capacity of 4.5 million tonnes per year each, four LNG tanks with a capacity of 180,000 cubic metres each, two marine jetties for oceangoing LNG vessels with capacities of 125,000-185,000 cubic metres, one turning basin and four LNG and two natural gas liquids (NGL) truck-loading bays. The pipeline system would include twin, parallel 42-inch (1,067-mm) diameter pipelines, three 180,000 hp compressor stations, two 30,000 hp interconnect booster stations, six mainline valve sites and four metering sites along a 2.4-mile (3.9-km) header system, as well as ancillary facilities. In other news, last week FERC authorised a proposed expansion of Sempra Energy’s Cameron LNG export terminal being built near Hackberry, Louisiana. Sempra proposed adding two liquefaction trains to the three already being built at Cameron LNG. Edited by Anna Kachkova annak@newsbase.com
Bidders line up for Bul Hanine phase-2 FEED PREQUALIFIERS for the design contract on the second phase of the multi-billion-dollar redevelopment of the offshore Bul Hanine field by stateowned Qatar Petroleum (QP) have been invited to submit bids in June. This lays to rest doubts about Doha’s commitment to proceed with the costly project in light of budgetary difficulties. Nevertheless, the scope may be somewhat smaller than envisaged at the launch of the strategically-important project two years ago – just weeks before the oil price slide began – as NEWSBASE
the state prepares to fall into its first fiscal deficit for more than a decade this year. Meanwhile, a reminder of the undecided fate of the Al-Shaheen field to the north – tendered among international oil majors in mid-2015 and offering a rare opportunity to obtain Gulf upstream equity – was provided by the longstanding incumbent operator Denmark’s Maersk Oil, in statements signalling less confidence than had previously been professed in the likelihood of its retaining the role. A shortlist understood to comprise Norway’s Aker Solutions, Fluor and Wood Group Mustang, both of the US, the UK’s Amec Foster Wheeler, France’s Technip and Australia’s WorleyParsons has been invited to bid by earlyJune for the front-end engineering and design (FEED) contract on the second phase of the project – launched in May 2014 and valued initially at US$11 billion – to redevelop Bul Hanine. The 80-square-km field that is operated by QP lays off the emirate’s east coast, having been discovered in 1972 and currently produces around 40,000 barrels per day. As originally conceived, the scheme aimed to roughly double production to around 95,000
June 2016
InnovOil
page 39
News in brief
bpd and – in keeping with Doha’s driving motivation across its various oil-producing assets – to extend the field’s life by around 25 years. The scope was to include drilling 150 wells, installing 14 new wellhead jackets, modifying existing jackets, and building a new central processing complex for the oil and a new natural gas liquids (NGL) plant at Mesaieed – connected by a 150- km subsea pipeline to the field. This will treat an estimated 900 million cubic feet (25.5 million cubic metres) per day of sour gas, returning dry gas to the field for re-injection. Work on the smaller first-phase of development is already under way. US-based McDermott won an engineering, procurement, construction and installation contract (EPCIC) in October covering four topsides weighing a combined 3,500 tonnes due for delivery by July 2017. Meanwhile, in January, WorleyParsons was selected for the FEED contract on the so-called phase 1B covering five topsides for wellhead platforms, pipelines, umbilicals and modifications to existing facilities. Edited by Ian Simm ians@newsbase.com
ITF-facilitated JIP to understand subsea faults enters trial phase A joint industry project established through The Industry Technology Facilitator (ITF) has entered a trial phase with the support of oil and gas operators. A new technology system designed to address a common problem in the subsea industry is undergoing a shallow water trial at Portishead Quays marina. The system will help to identify the location of electrical faults on subsea installations and will enable field operators to better plan for repair or replacement of failed components which could save the industry millions of pounds in halted production. The system, known as V-IR, has been developed by Viper Subsea with the support of Total, BP, Shell, and Chevron. NEWSBASE
The shallow water trial will run in phases and could last up to 12 months. The initial trial will take three months, during which time the V-IR technology suite will undergo communications and performance testing in a sea water environment that includes the use of 2km of subsea cable which has been deployed onto the bed of the marina. Although a shallow water trial, the main components are already designed for 3000m water depth. Following the shallow water trial there will be a period of further equipment qualification before the system is fully commercialised later in the year. ITF
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June 2016
InnovOil
What next …?
To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections
For more information, or to register interest in Phase 2 of DNV GL’s WINWIN project, contact Are Kaspersen, project manager for WIN WIN JIP on +47 416 33 831 or visit www.dnvgl.com/energy/ LumaSense Technologies’ Pulsar 4 temperature monitoring system is now fully compatible with HART protocols, offering operators even more versatility. To make an enquiry, contact Gerard Ames on + 31 651 648 299 or email info@lumasenseinc.com Visuray’s unique downhole x-ray imaging service looks to make troublesome stuck tools a problem of the past. To make an enquiry contact Angeline Tse at angeline.tse@visuray.com or visit www.visuray.com/ Interwell’s thermite P&A system could prove to be transformative for the decommissioning sector. If you’d like to know more, contact Terje Hauan, commercial manager for P&A on +47 400 04 399, or via email at pasales@interwell.com In its partnership with a number of service companies, Exceed is aiming to become a “one-stop shop” for decommissioning. If you think it could help you with your decom programme, contact John Anderson on +44 (0) 1224 577 940, or at info@xcd.com The addition of an acoustic lens has helped tackle the problem of beam defocusing in Kongsberg Mesotech’s oil-filled dome transducers. For more information on the innovation, contact Daryl Morse via km.sales.vancouver@km.kongsberg.com or visit www.km.kongsberg.com/mesotech
NEWSBASE
page 41
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