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Bringing you the latest innovations in exploration, production and refining Issue 48
EARS TO THE GROUND
The latest in seismic and geophysics Page 13
ETHANOL GOOD THINGS ORNL catalyst turns CO2 to fuel Page 6
MEDICAL MARVELS
The tech transfer transforming reservoir analysis Page 28
December 2016
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InnovOil
December 2016
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Inside Contacts: Media Director Ryan Stevenson ryans@newsbase.com
A note from the Editor
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Cunning catalysts
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MAS effect
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Run 3DMC
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Turning CO2 to ethanol at ORNL
Media Sales Director Charles Villiers Email: charlesv@newsbase.com
Steatite’s deep-sea battery project
Editor Andrew Dykes andrewd@newsbase.com
MacGregor’s motion compensator
On the Radar
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SEISMIC & GEOPHYSICS
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Phone: +44 (0)131 478 7000
Under pressure
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www.newsbase.com www.innovoil.co.uk
Wee-g causes big waves 16
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What caught out attention outside of oil & gas this month
European seismic struggles
New gravimeter could change gravity surveys
Design: Michael Gill michael@michaelgill.co.uk www.michaelgill.eu
South of the border Seismic picks up in Mexico
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Dolphin-friendly seismic 20 The search for marine vibrators
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ction ations in exploration, produ Bringing you the latest innov
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Autoships assembled
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Smarter particles
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A look at the PETGAS project for tight gas sands
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PET projects
Autonomous ship trials in Norway
and refining December 2016
Issue 48
Medical tech in oil and gas
Megaproject 30 Kashagan fires up once more
EARS TO THE GROUND
The latest in seismic and geophysics
Corrosive partnership
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News In Brief
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EMEC joins FORCE
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THINGS ETHANOLt GOOD turns CO2 to fuel ORNL catalys Page 6
VELS MEDICAL MAR r transforming
Contacts 37
The tech transfe reservoir analysis Page 28
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ITF launches Innovation Network to shine a light on SME Technology Development for the Oil & Gas Industry
The aim of the ITF Innovation Network is to provide an effective mechanism for technology developers to promote their technology development efforts to ITF members and the wider industry. This will be an active and evolving community where we will encourage discussion and engagement on technology qualification, field trials, joint industry projects and new technologies that can be quickly implemented on projects. Please register to join our community of Technology Developers, https://network.itfenergy.com or contact a member of our team at innovate@itfenergy.com for more information. FACILITATE COLLABORATE INNOVATE
www.itfenergy.com
December 2016
InnovOil
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A note from the Editor DESPITE ongoing turbulence in global politics and in the oil market, November has been a fairly encouraging month for the industry’s megaprojects. Most notably, commercial production began – or rather re-commenced – at the offshore Kashagan field in Kazakhstani waters of the northern Caspian. Output at the field, estimated to hold up to 13 billion-barrels of recoverable oil, rose above 75,000 barrels per day on November 1, Energy Minister Kanat Bozumbayev announced later in the month. The project has seen a slow return to life ever since a crack in a pipeline halted production in October 2013 – a direct result of the high levels of wet hydrogen sulphide gas present in the oil. With production first restarted in September 2016 the field is now on track to produce around 8.4 million barrels this year, and according to Bozumbayev will rise to somewhere between 30 million and 60 million barrels over the course of 2017. Despite its delays, the development remains an impressive technical feat. Similarly, Eni approved US$8-billion plans for its first phase of development at the Coral gas field offshore Mozambique. The Coral South project will see six subsea wells connected to a floating LNG (FLNG) facility capable of producing 3.3 million tonnes of LNG per
year. It also sends a strong signal that this combination of technologies – still in their relative infancy – increasingly resembles the future of offshore gas production. A final investment decision for the project is expected by the end of the year. Returning to somewhat smaller (although nonetheless revolutionary) innovations, this month we examine some of the latest technology and goings-on in the world of seismic and geophysics. Inside, we speak with researchers at the University of Glasgow who have developed wee-g – a gravimeter which they hope to make small and light enough to be mounted on a drone. We also take a look at the companies and projects aiming to make seismic more environmentally sound. In addition, this month also features a closer look at the PETGAS JIP – a project aimed at improving the characterisation of tight gas sands – and the current work of the Advanced Energy Consortium, which is redeploying medical technologies for oil and gas, creating “smart particles” and an MRI-like reservoir scanner in the process. All this, plus a cohort of autonomous ships, resilient marine coatings, electrifying catalysts and better marine batteries. We are pleased to present the December issue of InnovOil.
Andrew Dykes Editor
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InnovOil
December 2016
Spiked: ORNL catalyst turns CO2 into Ethanol Research from US’ Oak Ridge uses carbon and copper nanospikes to turn carbon dioxide and water directly into ethanol. The results could be of great significance for energy storage
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HE energy industry has long looked to bio-ethanol as a replacement for conventional fuels, and as a method of lowering CO2 emissions from transport. Other ethyl chains like methanol are often valuable by-products, or products in their own right. But were ethanol to be made efficiently and economically enough, its potential extends far beyond fuel and chemical production. A team at the US Department of Energy’s (DoE) Oak Ridge National Laboratory (ORNL) in the US may have stumbled on just such an opportunity. In researching the first step of a proposed reaction to convert CO2 and water to methanol, the team discovered that the catalyst used was causing the entire reaction. The study’s lead author, ORNL’s Adam Rondinone, added: “We discovered somewhat by accident that this material worked.” The reaction requires a nanostructured catalyst made of carbon, copper and nitrogen. When a voltage was applied, the catalyst reacted with the CO2 and water solution to produce ethanol – a method which the team says “essentially reverses the combustion process.” Moreover, the reaction is achieved at room temperature – the only inputs required, apart from the catalyst, are CO2 and water. Lightning rods This kind of electrochemical reaction is not new. Previous studies have produced smaller amounts of several different products – including carbon monoxide (CO), formic acid (HCOOH), methane (CH4) and ethylene (C2H4) or ethane (C2H6). However, as the researchers note in their paper, the efficiency of these methods is not great, and the chains produced are limited – most reactions will only produce “single-digit percentages” of liquid hydrocarbons, and are unlikely to produce any molecule heavier than methane in sufficient quantities to be practical.
Copper nanoparticles (seen as spheres) embedded in carbon nanospikes. Source: ORNL
Yet the ORNL reaction appears to be reasonably efficient, at least in terms of the end product. The process converts water and CO2 into ethanol with a yield of 63% at 1.2 V, with other marginal amounts of pure hydrogen (H2), CO and CH4. Depending on the sample size, the yield in some tests was as high as 70%. Despite some of the media bluster around the process, it is not the answer to the world’s CO2 emission problems. CO2 is stored temporarily in the form of ethanol, and the process is a net consumer of energy. Nevertheless, if its relative simplicity can be paired with economic and technical efficiency, the possibilities are intriguing. “We’re pushing [the] combustion reaction backwards with very high selectivity to a useful fuel,” Rondinone said. “Ethanol was a surprise – it’s extremely difficult to go straight from carbon dioxide to ethanol with a single catalyst.” The design and structure of the catalyst is the secret to the team’s success. Copper NEWSBASE
nanoparticles are embedded in “randomly oriented nanospikes” of carbon around 50-80 nanometres long, and which end in a curled tip around 2 nanometres wide. According to Rondinone, these spikes “are like 50-nanometer lightning rods that concentrate electrochemical reactivity at the tip of the spike.” According to the team’s paper on the subject, these reactive sites “work in tandem to control the electrochemical reduction of carbon monoxide dimer to alcohol,” ensuring that the conversion happens efficiently and uniformly, and produces the specific alcohol as desired. The paper adds: “The Cu/CNS catalyst is unusual because it primarily produces ethanol rather than methane or ethylene. Ethanol, as a C2 product, requires carboncarbon coupling between surface-adsorbed intermediates at some point during the reduction reaction. Recent calculations on C−C coupling on Cu(211) surfaces suggest the kinetic
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ORNL’s Yang Song (seated), Dale Hensley (standing left) and Adam Rondinone. Source: ORNL
barriers for the coupling are strongly influenced by the degree of the adsorbed CO hydrogenation.” Storage hunters By using commonly available elements and better structuring, the hope is that such catalysts could also cheaper and easier to produce than current iterations, which typically rely on expensive and rare metals. That opens the door to new catalytic conversions which may have previously been considered uneconomic. Because the reaction can be performed at room temperature, there is hope that the process could be scaled up into industrial applications – this is where energy storage comes in. The researchers suggest that excess electricity from variable power sources – renewables such as wind and solar especially – could be used to drive large-scale plants using the catalyst, enabling them to store energy in the form of ethanol. “A process
like this would allow you to consume extra electricity when it’s available to make and store as ethanol,” Rondinone said. “This could help to balance a grid supplied by intermittent renewable sources.” Re-deploying that energy again is another issue. It is unlikely to be used in utility-scale power generation, although it could be effective as a means of powering mini-grids or small generators. It could also be blended into gasoline or used directly as a transport fuel, or it could simply be sold as a useful product much like the methanol produced by gas-to-liquids (GTL) systems. Most importantly, however, that fuel would be effectively carbon-neutral (provided it was generated by renewable sources). That provides a valuable incentive for refiners and hydrocarbons producers to get on board, if the process could be made economic. For now, however, the process is still in the experimental stage. The researchers now plan to refine their approach to improve the NEWSBASE
overall production rate and further study the catalyst’s properties and behaviour. One key limitation is outlined in the paper’s conclusion. High overpotential in the reaction means that less energy is recovered than is used for the transformation, the majority of which is lost through heat. The team notes that although this could be lowered “with the proper electrolyte, and by separating the hydrogen production to another catalyst,” this loss “probably precludes economic viability for this catalyst.” Yet other designed catalysts may not. Increased “selectivity” in future nanostructure designs could enable catalysts capable of manufacturing other hydrocarbon chains like methane, ethylene and ethane. In a curious twist, the future of efficient energy storage could yet lie in hydrocarbons. n Contact:
Email: mccorkleml@ornl.gov Web: www.ornl.gov
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InnovOil
December 2016
MAS effect
A consortium led by UK-based Steatite completes first phase of pioneering battery development project
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S more subsea vehicles become capable of autonomous operation, so too do the demands for longer and more flexible options for powering them. Lithium-ion batteries may be improving by the day in land and aerialbased electric vehicles, but devising systems which can stand up to the temperatures and pressures of subsea work is altogether more challenging. Nevertheless, some have made headway. A consortium led by electronics and communications firm Steatite is currently undertaking a two-year project to produce battery packs which will be pressure tolerant at depths of up to 6,000m, with a view to incorporating them into more Marine Autonomous Systems (MAS). Supported by InnovateUK and the Defence Science and Technology Laboratory (Dstl), the project involves expertise from multiple companies in the supply chain, including Lithium Sulphur (LiS) cell manufacturer OXIS Energy, underwater vehicle designers and manufacturers MSubs and scientific expertise from the National Oceanography Centre (NOC). The hope is that such systems will not only allow autonomous vehicles to reach these depths, but that they will be able to do so more safely and with increased range, speed and payload capacity. In doing so, the vehicles can remain subsea for longer periods, reducing the costs of deployment and operation.
Under pressure According to the group, pressure testing at the NOC has formed the bulk of the work so far. At 6,000m, subsea pressures exceed 600 bar, yet components must continue to deliver the output required to run the vehicle. Temperature is also problematic (batteries tend not to like the cold), and tests have included cycles run at 0-4°C. However, these tests have produced concrete results. The latest generation of 12Ah Li-S Oxis cells have a raw energy density of 289 Wh/kg, a 70% improvement on comparable Lithium-Polymer performance. By the end of the project, the consortium is aiming to produce a commercial pack with twice the capacity of the current market leader, Steatite battery Paul Edwards told InnovOil. To achieve this, over successive prototype the group has almost managed to overcome the loss of energy density at lower temperatures, allowing Li-S cells to deliver nearly the same amount of charge under working pressures and temperatures as in ambient temperatures. This was done, Edwards said, by close work with cell supplier Oxis, enabling the supplier to redesign the construction of its cells in the wake of each test. Vehicle power supplies must also remain neutrally buoyant over the mission, a requirement which necessarily lowers the NEWSBASE
available battery storage. The resulting Neutral Buoyancy Energy Density (NBED) value of Li-S is lower, at 126 Wh/kg, but is almost twice as dense as the comparable LiPo cell, at 66 Wh/kg. According to project documents, the group has successfully performed a number of life cycle tests with several cells, achieving 60 cycles of slow discharge – e.g. an AUV travelling at slow constant speed and recording data – and 80 cycles of “faster” discharge, such as an ROV travelling at speed to a work site and being used to service equipment. That success suggests that these batteries could be used either to substantially extend the operating time of vehicles using current battery architecture, or would allow designers to reduce the battery size by half, whilst maintaining or improving current operating life and freeing up more space for payload. The most recent update marks the project’s halfway point. From now and into 2017, the group will work on into the battery development phase, including work developing on Steatite’s Battery Management System (BMS). Following this, the battery will be demonstrated in a “deep-dive” submarine in the middle of next year. n Contact:
Email: mas@steatite.co.uk Web: www.steatite.co.uk
December 2016
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MacGregor makes a claim on motion compensation A retrofit 3D motion compensator can enhance the precision and flexibility of a wide range of cranes
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S vessels and assets age, many are pushed to work to far different specifications than may have been originally envisioned. With advances in new equipment however, retrofitting is often an economical and practical way of expanding the operational envelope. In that vein, offshore engineering firm MacGregor has developed a 3D motion compensator (3DMC) for offshore cranes. The device can be retrofitted to the company’s crane range – either on vessels or platforms – and is designed to enhance loadhandling precision. The result is an increase to the accuracy and flexibility with which the vessel can operate, even in rough seas. MacGregor senior vice president for Technology and R&D, Alexander Nürnberg, explains that: “The 3DMC can be fitted to the knuckle jib of a broad spectrum of new or existing MacGregor subsea/offshore cranes. It compensates for the roll, pitch and heave motions of the vessel to minimise any movement of the load in relation to a fixed point in space.” MacGregor explained to InnovOil that the unit is designed with a safe working load (SWL) of 5 tonnes and is designed to compensate for a significant wave height of 4 metres, although this will vary based on the vessels stability. While the standard AHC – supplied through a crane’s winch – compensates for a vessel’s vertical movements, more accurate positioning is sometimes required. The 3DMC therefore allows shipowners to expand the load-handling capabilities of a crane far beyond its original limitations. Flexible friend According to the company, the unit can be easily installed and integrated into the crane, connecting to the existing hydraulic power unit and control system. So straightforward in fact, that MacGregor suggests that a fleet of vessels could share a one (or a number of) units, equipping them for specific missions whenever necessary. The 3DMC is fully incorporated into the
crane’s control system, so that all operations are managed from the existing interfaces in the crane cabin. When the user needs to transfer equipment to or from offshore wind turbine structures or fixed platforms, the operator can opt to use the 3DMC. When not required, the 3DMC simply remains fixed to the side of the crane’s knuckle jib allowing normal lifting operations using the main and whip winches. The company’s director of Advanced Offshore Solutions and Global Lifecycle Support, Gaute Sjusdal adds that: “This means that the crane and therefore the vessel can be used for more assignments and owners will be able to bid on a wider range of contracts.” At a cost of around 800,000 euros (US$850,000), it seems a fair proposition for increased versatility. Renewables appear to be the target NEWSBASE
market for the innovation, with a particular focus on using the 3DMC to accurately supply and transfer equipment from vessels onto wind turbine platforms. As more supply vessels aim to diversify operations, or at least to split time more evenly between renewables and oil and gas, innovations such as this are likely to have a major impact on working fleets. Indeed, in an emailed reply to InnovOil, the company added that: “The reception and interest from the offshore industry has been very good. The benefit of adding specific operation capabilities to existing equipment has a noticeable high appeal to owners.” n Contact: Heli Malkavaara
Tel: +358 20 777 4500 Email: Macgregor@macgregor.com Web: www.macgregor.com
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On the radar
What caught our attention outside the world of oil and gas this month
Super (cala) hydrophobic Researchers may have found a cost-effective and environmentally friendly method of applying a super-hydrophobic layer to objects, which could enable new uses in anti-icing, anti-sticking and self-cleaning applications. Professor Dong Sung Kim, research professor Donghwi Choi and fourth-year undergraduate student Jaewon Yoo at the Department of Mechanical Engineering at Pohang University of Science and Technology (POSTECH) have developed the super-hydrophobic layer using commercially available salt particles, polydimethylsiloxane (PDMS) and water. The goal is to replicate the lotus effect – the process whereby water droplets, along with any dirt particles, roll off the surface of a leaf – to other surfaces. This has been achieved by simulating similar micro- and nanoscopic
surface designs in the past, but applying these hydrophobic coatings requires complicated procedures with high equipment costs and harsh chemicals. As a result, making a stainrepellent fabric or a self-cleaning building can be very difficult. The research team instead used a salt-dissolution assisted etching process, taking advantage of the fact that salt readily dissolves in water. A salt-particle-embedded PDMSD surface was exposed to an aqueous environment, while the remaining PDMS surface becomes roughened with micro/ nano-hierarchical topography, creating a super-hydrophobic surface. Encouragingly, they claim that the process can also be applied to large or three-dimensional surfaces. Their results were recently published in Applied Surface Science. n
December 2016
Weapons health check The Air Force Research Laboratory Munitions Directorate (AFRL/RW) has signed an educational partnership agreement (EPA) with Iowa State University of Science and Technology, which will see the two bodies collaborate on structural monitoring systems for high-speed structures. Current techniques mean that these systems, such as weapons and weapon airframes, can only be inspected when not in use. According to an AFRL release, the structural health monitoring (SHM) programme would integrate sensor networks and structures to examine and detect damage during operations autonomously. “While SHM systems allow for continuous measurement of gradually changing structures on the order of milliseconds to minutes, there is a lack of real-time methods that can detect, and characterise, damage in the microsecond time scales,” AFRL said. The development of SHM into microsecond structural health monitoring (μSHM) systems is critical to the reliable operation of next-generation high-speed complex structures (e.g. hypersonic air vehicles and weapon airframes). This should allow these systems to increase functional reliability and decrease maintenance costs. Iowa State may also use the technology as a stepping stone for the development of methods to apply to civil structures, future aircraft and spacecraft. n
LEDs foiled again Researchers at Ohio State University have developed lightemitting diodes (LEDs) on metal foil. The innovation would allow LEDs to be used in portable ultraviolet (UV) lights for water purification and sterilisation. High-energy, or “deep”-UV light sources have long been used for these applications – as well as to cure plastics and detect biological agents – but have been too heavy and cumbersome to be portable. Moreover, they contain harmful substances. “Right now, if you want to make deep ultraviolet light, you’ve got to use mercury
lamps,” said associate professor of materials science and engineering at Ohio State, Roberto Myers. “Mercury is toxic and the lamps are bulky and electrically inefficient. LEDs, on the other hand, are really efficient, so if we could make UV LEDs that are safe and portable and cheap, we could make safe drinking water wherever we need it.” Previous attempts at making deep-UV LEDs required the use of extremely pure, rigid single-crystal semiconductors as substrates. Using foil is cheaper, lighter and more environmentally friendly. Instead the team used a
semiconductor growth technique known as “molecular beam epitaxy”, in which vaporised elemental materials settle on a surface and self-organise into layers or nanostructures. They allowed the team to grow a carpet of tightly packed aluminium gallium nitride wires on pieces of metal foil such as titanium and tantalum. The individual wires measure about 200 nanometres tall and about 20-50 nanometres in diameter. According to researchers, in tests these nanowires lit up nearly as brightly as those manufactured
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on the more expensive and less flexible single-crystal silicon. Subsequent research will look at growing them on more common metals such as steel and aluminium. The team’s research was recently published in Applied Physics Letters. The university intends to license the technology to industry for further development. n
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Ultra-strength from welded nanotubes Researchers from the Moscow Institute of Physics and Technology (MIPT), Technological Institute for Superhard and Novel Carbon Materials (TISNCM), Lomonosov Moscow State University (MSU) and the National University of Science and Technology MISiS have shown that an ultrastrong material can be produced by “fusing” multiwall carbon nanotubes together. According to the scientists, such a material could endure extreme conditions, making it useful for applications in aerospace and other industries. The researchers’ paper studied the effect of high pressure on multiwall carbon nanotubes (MWCNTs). In addition, they simulated nanotube behaviour in high-pressure cells, finding that the shear stress and strain in the outer walls of the MWCNTs caused them to connect to each other as a result of the structural rearrangements on their outer surfaces. The inner concentric nanotubes, however, retain their structure completely: they simply shrink under pressure and restore their shape once the pressure is released. These experiments were performed at pressures of up to 55 GPa, which is 500
times the water pressure at the bottom of the Mariana Trench. The main feature of this study is that it demonstrates the possibility of covalent intertube bonding giving rise to interconnected (polymerised) multiwall nanotubes; these nanotubes are cheaper to produce than their single-wall counterparts. “These connections between the
nanotubes only affect the structure of the outer walls, whereas the inner layers remain intact. This allows us to retain the remarkable durability of the original nanotubes,” comments Professor Mikhail Popov of the Department of Molecular and Chemical Physics at MIPT, who heads the Laboratory of Functional Nanomaterials at TISNCM. n
Graphene enables fuel-cell breakthrough Layers of graphene separated by nanotube pillars of boron nitride may be a suitable material to store hydrogen fuel in cars, according to a new study from Rice University. The Department of Energy has set benchmarks for storage materials that would make hydrogen a practical fuel for light-duty fuel cell vehicles (FCVs). Rice lab of materials scientist Rouzbeh Shahsavari and colleague Farzaneh Shayeganfar determined in a new computational study that “pillared boron nitride and graphene” could be one potential candidate. Shahsavari’s lab had already determined through computer models how tough and resilient pillared graphene structures would be, later adding boron nitride nanotubes to model a unique three-dimensional
architecture. These pillars in boron-nitride graphene make space for hydrogen atoms. They focused the simulations on four variants: pillared structures of boron nitride or pillared boron nitride graphene doped with either oxygen or lithium. At room temperature and in ambient pressure, oxygen-doped boron nitride graphene proved the best, holding 11.6% of its weight in hydrogen (its gravimetric capacity) and about 60 grams per litre (its volumetric capacity). This trumps competing technologies like porous boron nitride, metal oxide frameworks and carbon nanotubes. At -321°F (-196°C), the material held 14.77% of its weight in hydrogen. The Department of Energy’s current target for economic storage media is the ability to store more than 5.5% of its weight and 40 grams per litre in hydrogen under moderate NEWSBASE
conditions. The ultimate targets are 7.5% and 70 grams per litre. Shahsavari said hydrogen atoms adsorbed to the un-doped pillared boron nitride graphene, thanks to weak van der Waals forces. When the material was doped with oxygen, the atoms bonded strongly with the hybrid and created a better surface for incoming hydrogen, which Shahsavari said would likely be delivered under pressure and would exit when pressure is released. He said the structures should be robust enough to easily surpass the Department of Energy requirement that a hydrogen fuel tank be able to withstand 1,500 charge-discharge cycles. Shahsavari and Shayeganfar’s study appears in the American Chemical Society journal Langmuir. n
InnovOil
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SEISMIC & GEOPHYSICS SPECIAL SUPPLEMENT Pages 13-22
WEE HAPPY FEW A gravimeter innovation from Glasgow Page 16
TOUGH TIMES
European seismic operators take stock Page 14
SAFER SEISMIC Dolphin-friendly vibrations Page 20
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InnovOil
December 2016
SEISMIC & GEOPHYSICS
Europe’s seismic operators still under pressure Third-quarter results show that times are tough for Europe’s geoscience firms, writes Martin Clark
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HE fallout of the oil price crash continues to be a drag on the performance of Europe’s geoscience firms. They have been the victims of reduced capital expenditure on exploration in the North Sea and in other producing basins around the world. The recent raft of results from major seismic contractors for the third quarter revealed continued weakness in the market, though there are signs that next year will be better. France-based CGG’s results highlighted its problems, with its debt pile totalling US$2.3 billion at the end of September. Reporting its Q3 results, the company said that while its fleet was still busy, the market outlook was still very challenging. “The context of rising crude prices did not yet translate for our industry in
improved market conditions, which remain difficult,” said CEO Jean-Georges Malcor. He blamed the tough operating environment for substantially reduced Q3 revenues of US$264 million – down by almost 44% year on year. Net losses for the same period stood at US$88 million. Given its substantial debts, CGG is understandably focused on costs and containment, though this could take a while to filter through. The firm aims to keep its net debt below US$2.4 billion by the end of 2016 as part of an overall plan to address its capital structure. “We remain fully focused on strict cost and cash management and on preserving our liquidity,” Malcor said. More encouraging for CGG is that its reputation in the market remains strong and its services are still in high demand, though activity is largely being driven out of NEWSBASE
Europe. The company won a couple of new contracts in October for seismic shoots in Mexico and Mozambique. There is still work to be won in the European market, notably in frontier areas such as the Barents Sea. In September, Oslo-listed Spectrum began the acquisition of a new 1,800-square km multi-client 3D seismic survey offshore Norway in the western Barents Sea. The frontier area has attracted considerable interest from the energy industry in recent years. The new data will be available during the first half of 2017, ahead of the 24th Norwegian licensing round next year. Spectrum, which also posted losses when it issued its third-quarter results at the end of October, is likewise more upbeat about prospects going into next year, a common theme.
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SEISMIC & GEOPHYSICS Seismic survey, oil research and exploration in the North Sea.
“Rising crude prices did not yet translate for our industry in improved market conditions” Jean-Georges Malcor, Chief Executive Officer, CGG Veritas
Schlumberger’s WesternGeco also cited increased marine survey activity in the North Sea, resulting in a modest Q3 boost for its so-called Reservoir Characterisation Group. While much of its other activity was again elsewhere, it highlights that there is still business to be done offshore Europe. “Revenue was 5% higher sequentially due to increased WesternGeco marine surveys in the North Sea,” Schlumberger announced in its results update in late October, although its backlog fell on the previous quarter. The company was involved in the UK Oil & Gas Authority (OGA) funded seismic shoot to gather data to help spur more exploration on the UK Continental Shelf (UKCS). PGS, which also played a part in the UK government-funded project, was another company to cite “challenging conditions”
in its third-quarter assessment. Its order book slipped to US$190 million at the end of September, down from US$245 million a year earlier. Amsterdam-listed Fugro also sees total spending contracting this year, citing a general market consensus, but flattening out in 2017. While the oil and gas sector still accounts for three-quarters of its work, it has been keen to diversity into other markets, including offshore renewable energy projects and land-based buildings and infrastructure. Dubai-based Polarcus, which is listed in Oslo, is also weathering the storm, citing high fleet utilisation in Q3. But it also recorded a drop in overall revenues during the same period. While its results were comparatively robust, it noted that NEWSBASE
the seismic market continued to look challenging in the near term with the expectation of reduced tendering and prefunding activity during the coming northern hemisphere winter season. The company said it would continue to focus “on areas within its direct control”, though it has also enjoyed some success in the European market, notching up another 3D marine seismic acquisition project in September. There will be no quick fix for any of these leading seismic operators, with industry conditions remaining difficult and exploration capex down significantly from previous years. But they continue to hang in there and will be well placed to take advantage when prevailing conditions eventually improve. n
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December 2016
SEISMIC & GEOPHYSICS
Transforming gravity surveys with wee-g Dr Giles Hammond discusses wee-g, a radical new MEMS-based gravimeter which could enable gravity surveys to be performed by drone within a matter of months
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RAVITY surveys are an expensive business. Requiring multiple readings spread across hundreds of miles, they are labour-intensive for geophysicists. For larger operations, in addition to the cost of using offshore vessels or aircraft, surveys also require gravimetry equipment – used to measure the local acceleration of gravity, and which can infer mineral and hydrocarbon deposits deep underground. They can also weigh hundreds of kilos and cost hundreds of thousands of dollars. To put that in perspective, the industryleading LaCoste FG5 – an absolute gravimeter – costs around US$200,000 and weighs about 200kg. A more portable, relative gravimeter like the SCINTREX CG-5 will go for around US$75,000 and weighs a more manageable 10kg, but requires many hours of manual readings, as well as GPS co-ordinates and elevation recordings to record an accurate survey. Making equipment more cheaply and the process of measurement easier would not only offer a vital lifeline to an industry struggling with low prices, but could change how the industry undertakes resource surveys altogether. That may now be possible, thanks to a tiny gravimeter developed by a team at the University of Glasgow. Based on cheap and mass-producible micro-electromechanical systems (MEMS), their innovation combines the server-sized technology of geophysical surveys with the everyday portable accelerometers found in a smartphone. But while the so-called “wee-g” – a nod to the city of its birth – may be small in scale, the implications of the technology are not. These were qualified in an early 2016 paper published in Nature, in which the device’s creators successfully measured the Earth tides – the elastic deformation of the Earth’s crust caused by the pull of the Sun and Moon – by calculating the changes in the planet’s magnetic field from the basement of the University.
The wee-g system on mount
The device owes a lot to the recent advances of nanotechnology. Developed at the University’s James Watt Nanofabrication Centre, wee-g is the result of a crossdisciplinary effort between the School of Physics and Astronomy (Institute for Gravitational Research) and the School of Engineering (Electrical & Nanoscale). InnovOil spoke with Dr Giles Hammond of the first department to find out more. Resonating thought “I realised three years ago that we could build small form-factor silicon-based resonators – micro-electromechanical sensors (MEMS) – but make them a lot more sensitive than current devices,” Hammond explained. Indeed, the use of silicon is key to the accuracy of the device. “When you build MEMS devices, the thing that defines how much deflection you get on the proof mass – what happens when gravity changes – tends NEWSBASE
to be quite stiff.” As a result, accelerometers in the average phone can measure deviation from the standard gravity (1G), but little more beyond that. But by developing a manufacturing process which could produce very soft, low frequency resonators, the accuracy of a very similar system could be improved by many orders of magnitude. Using a highly sensitive silicon spring “ten times thinner than a human hair,” a 12mm sensor in the wee-g can detect the minute changes in gravity needed for survey applications. Hammond quantified this more specifically, explaining: “Our MEMS devices oscillate up and down at about 2Hz, whereas the ones in a smartphone may be around a few kHz.” Hammond worked with Engineering Professor Douglas Paul and PhD student Richard Middlemiss to develop the gravimeter and to publish the aforementioned paper. In addition to sensitivity, the team was able to
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SEISMIC & GEOPHYSICS The MEMS in enclosure
show a notable achievement in engineering stability. He explained: “We can now monitor the position of our proof mass in the device to about 2 nanometres over five to six days… To do that, we had to control the temperature of the device in many places, because it will change the thermodynamic properties of the spring.” According to Hammond, that perceived lack of stability is what has held back MEMS technology thus far. “That’s why MEMS devices haven’t pushed into the market. They’re quite standard for seismic surveys but for seismometer surveys you need short-term stability over 5-10 seconds – whereas we are showing good stability over 5-10 days.” In doing so, the research pushes MEMS technology into new realms. Array of options The playing field between the wee-g and existing equipment is not yet an even one.
Although thousands of times more sensitive than the average accelerometer, it is about ten times less sensitive than the best devices available. Nevertheless, according to the team, it is still capable of sensing a tunnel of 2m2 at a depth of 2m, and could be used to find an oil deposit of 50 cubic metres at depths of up to 150m. Its real benefits stem from the improvements that could be made to surveys themselves. “Because our devices are MEMS devices, potentially they could be a lot cheaper than US$75,000 as they’ll be developed out of standard processing,” he said. Indeed, the team has previously estimated that they could be in the region of US$100 a unit. That cost base, he continued, “would allow us to have a sensor array, which opens up a new way of sensing the gravitational field, more like a seismic survey.” He envisions a system with a number of sensors set down across an area which NEWSBASE
can take measurements over a defined period before being moved on, allowing surveys to be conducted far more quickly than is currently manageable with a relative gravimeter. The wee-g device is now being developed into a prototype which would support an autonomous system, logging data automatically to an SD card. The final iteration of this system is some way off, but the team has already embarked on a project with geosciences firm Bridgeporth to undertake “comparative, side-by-side field surveys” which will help qualify the resolution and accuracy of the wee-g against the current state of the art. Defying gravity With the concept proven and a paper published in March, most of this year has been spent working the wee-g prototype into something more commercial and field-ready. “We started off with a lab-based system –
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December 2016
SEISMIC & GEOPHYSICS Left to right: Douglas Paul, Steven Bramsiepe, Richard Middlemiss and Giles Hammond
everything running on mains power and rackmounted electronics. What we’ve done in the last 6 months is taken all our electronics and miniaturised it to something less than half the size of a piece of A4 paper,” Hammond said. The wee-g now consists of a card of electronics run by a digital signal processor, and powered by standard 12V batteries. “We’ve also miniaturised the vacuum system, so now we have something that weighs about 3kg and fits in your hand,” he continued. Looking ahead, this is only set to get more ‘wee.’ “The final device will be put into a standard MEMS package, typically about 15mm x 15mm x 15 mm – a little cube with a self-contained vacuum and the device will sit in there,” he added. This paves the way for the next stage of development, slated to be completed by mid2017. Once this occurs, one begins to see the truly disruptive effects the technology could have. “We’re really thinking about taking the current devices of about 10kg and shrinking them down to about 100g. That’s exciting,
because when you make them that light, you can mount them on drones,” Hammond enthused. This as Hammond has said, opens up new ways of sensing. “The thought is that we can get away from using these traditional aircraft and get over to a drone-based survey. If you make something light and cheap, then in principle we’re looking to work with end users to do some surveys on drones.” A few highend drones, equipped at a total cost of a few thousand dollars each, could then perform a survey which may currently cost well into the hundreds of thousands. As the autonomous flight capabilities of drones increase further, even larger areas could be covered in greater detail, without the need for clear weather and a charter aircraft. From there, the landscape of gravity surveying begins to look very different indeed. While the latter may be a few years off, the team is confident that next year will see the next stage of the project take off. “By mid-2017 we would like to have this packaged into its NEWSBASE
small form factor… By then we’d really like to have a device that we can give out to end users. Within a year I’d say we should be at the point at which we could put this thing on a drone.” Unsurprisingly, the proposition has generated a lot of interest, Hammond said, with “tens of companies” getting in touch to request access to the technology. In addition to the trials being run with Bridgeporth, the group has an ongoing optical sensing project with Schlumberger and is working with nearby Clyde Space to include the gravimeter as a sensor package within one of the company’s mini CubeSat satellites. For now, the team has plenty to get on with to meet their 2017 deadline. Beyond that, InnovOil suspects that it may not be that long before the wee-g starts to make big waves in the geoscience sector. n Contact Dr Giles Hammond Tel: 0141 330 2258 Email: giles.hammond@glasgow.ac.uk Web: www.physics.gla.ac.uk/igr
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SEISMIC & GEOPHYSICS
Seismic activity picks up in Mexico A number of firms are now shooting offshore surveys and reprocessing earlier scans for shale deposits
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TATE -run Pemex abandoned seismic studies entirely for the first nine months of 2016, as part of a sharp cost-cutting measures brought in at the start of the year. The firm had shot 645 square km of 2D seismic in 2015, and 485 square km of 3D, before work dried up between January and September this year. But data released by Mexico’s General Ports and Merchant Marine Authority (CGPMM) last week suggest activity is beginning to ramp up again. The authority said that eight ships working for Schlumberger subsidiary Western GECO were shooting 3D seismic in the area around the Suuk well in Pemex’s AmocaYaxche-0004 Block. The company was granted regulatory approval to explore the area, which has average water depths of 45 metres, in April 2015. Pemex has company in the area too. A second exploration project to shoot 40 square km of 2D seismic in the Hokchi field is also currently under way. Four vessels are conducting the work for Argentine firm Pan American Energy (PAE), which won the asset in the shallow-water tender held in September 2015. Separately, in November the National Hydrocarbons Commission (CNH) issued permits for new seismic data reprocessing work to a firm called Seismic Enterprises Mexico (SEM). The permits are part of a broader framework, called the Permits for Surface Exploration and Survey (ARES), that was brought in under Mexico’s broad energy reform in August 2014. ARES allows companies to carry out seismic surveys at their own risk, without automatically giving them the right to explore or produce based on the data they have found. The CNH has so far issued 43 permits based on this scheme to 23 companies. France’s CGG has secured six permits, with Norway’s PGS picking up five. Schlumberger and US-based Seitel each received four permits.
Campeche Reimaging
The Campeche reimaging program combines 60,000 km2 of narrow-azimuth (NAZ) surveys in the prospective Campeche basin. Using the latest imaging technologies, Schlumberger is providing high-quality and cost-effective understanding of this area in advance of the upcoming bid rounds. A total of 52 firms have won approval to join a shortlist of prequalified ARES firms, but most have not submitted projects. Indeed, only 17 of the permits have actually triggered new data acquisition projects. A further 12 permits are for reprocessing earlier scans and the remaining 14 have either been returned to the CNH or allowed to expire unused. SEM’s permit is for reprocessing data NEWSBASE
from some 56,500 square km of the Burgos Basin, an onshore area close to the US border that produces close to a fifth of the country’s natural gas output and holds a quarter of its proven reserves. SEM is looking for evidence of shale in deposits called Pimienta, Agua Nueva and Basamento, areas that already yield conventional dry gas. n
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SEISMIC & GEOPHYSICS
A farewell to harms – seismic surveying gets friendlier
The intense subsea sounds produced when conducting seismic surveys using traditional impulse sources are having a major negative impact on marine mammals. Tim Skelton looks at some of the innovative and more environmentally friendly alternatives
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HE impulsive sound sources used for seismic oil exploration and monitoring include dynamite blasting and, more commonly, high-powered air guns. But they have also long been blamed for harming the environment and sea life in survey zones. Air guns in particular are responsible for some of the loudest man-made sounds in the sea, sometimes passing 250 decibels (dB). Moreover, as a side-effect they emit high frequency pulses that are not useful for surveying purposes, but which can cause injury and hearing loss in whales and dolphins, as well as disturbing essential behavioural patterns such as feeding, breeding and inter-communication. Such concerns gained wider exposure in September this year when the US Bureau of Ocean Energy Management (BOEM) released a draft environmental impact statement that concluded that oil and gas exploration seismic surveys in the Gulf of Mexico were causing significant harm. It suggested that as many as 32 million marine mammals might potentially be injured and/or harassed, including several endangered species of whale. The draft outlined a number of possible measures designed to mitigate the effects and protect marine mammals and coastal environments. These included banning seismic surveys entirely in certain ‘closure areas’, and reducing activity in others. In parts of the Gulf of Mexico, the agency recommended that energy companies conduct their surveys with observers on hand to monitor the presence of protected species. The American Petroleum Industry (API), the trade association representing the industry in North America, already believes that seismic surveys are highly regulated and says they are performed “only in government-
Teledyne seismic bubble resonator source prototype
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licensed areas where operators make great efforts to prevent potential impacts on marine life.” It has also stated that surveys begin with a ‘softstart’, gradually increasing sound levels to allow sensitive animals to leave the area. Nevertheless, the BOEM study suggests that more still needs to be done. Good vibrations There could already be an alternative, far easier and safer solution out there that would avoid the need for drastic measures such as an outright ban. California-based GPUSA has developed an innovative new Marine Vibrator for use in seismic surveys. The company’s patent-pending MV-24 model, originally reported on in the December 2015 issue of InnovOil, has – quite literally – less of an impact on the surrounding environment whilst still providing the desired data quality, or even better. NEWSBASE
GPUSA says the answer is to keep operating frequencies at low levels that are less harmful to marine life. This means replacing the impulsive sound sources with vibratory sources. “Impulsive sources create significant broadband noise (up to 1,000 Hz), with much of it outside the useable seismic frequency band. But while frequencies above about 100 Hz are typically not seismically useful, they are still blamed for the preponderance of the harm to marine life,” CEO Jim Andersen explains. “A marine vibrator that can impart controlled vibrations over a period of many seconds, as compared to milliseconds from an impulsive source, has many advantages,” he continues. “At the most basic level it must cyclically displace large volumes of water over the seismic band of interest, but it can be limited to [a maximum frequency of] approximately 100 Hz and thus would eliminate the environmental concerns.” In addition, a precisely controlled source that is highly repeatable can even improve imaging results compared to impulsive
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SEISMIC & GEOPHYSICS The MV-24 Marine Vibrator has 24 inch diameter opposed piston transducers sealed to a rugged high performance flexible tire bead for long life
sources that are far less repeatable. Several competing designs are currently in development as part of the Marine Vibrator Joint Industry Project (MVJIP), which is being sponsored by oil majors ExxonMobil, Royal Dutch Shell and Total, and managed by Texas A&M University’s Global Petroleum Research Institute (GPRI). The project is an ongoing five-year plan to develop, design, construct and test a commercially viable alternative to air guns, and three manufacturers were contracted in 2013 and 2014 to come up with prototypes. According to a paper presented at the American Association of Petroleum Geologists (AAPG) and the Society of Exploration Geophysicists (SEG) conference in September 2016, the parameters of this JIP were for designers to devise systems which had a five-second signal array output, had a harmonic content above 150 Hz when driven with tone in 5-100 Hz range, and which could sweep for 72 hours between maintenance, among other criteria. The three MVJIP solutions are ‘flextensional transducers’ (being developed by PGS), ‘dual port, doubly resonant bubble’ seismic sources (the work of Teledyne), and a so-called ‘Moving Coil Transducer’, the idea of General Dynamics subsidiary Applied Physical Sciences (APS). According to research papers, Teledyne’s solution is a “coherent seismic marine sound source technology based on the application of an underwater, gas-filled bubble as a low frequency resonator.” APS’ variation is “an underwater sound projector for producing time-harmonic waveforms comprise[d of] two pistons positioned on either side of a single electro-magnetic force generator,” according to patent filings.
In comments made to the AAPG earlier this year, the man behind the JIP, David Burnett, said: “By 2017, we’ll have equipment testing in the open water environment, and the information will be public.” However, while work is now under way and participants are focused on delivering technology before 2020, all three are still several years away from being available for use aboard a typical seismic vessel. Andersen thinks the designers of these systems may be making life too hard for themselves by over-complicating their solutions. “They are trying to adapt conventional high- and mid-frequency sonar technology, and it doesn’t really fit,” he thinks. “Designing a sonar transducer to sweep from zero to 100 Hz is very different from designing one to operate at 1,000 Hz to 10,000 Hz. To get the desired amount of power at these low frequencies requires the ability to move or displace 50 litres or more of water.” Simpler times An alternative approach makes the GPUSA system different. According to Andersen, keeping things simple has been the key. “Our marine vibrator uses a rotating crankshaft, connecting rods and ‘pistons’ (stiff transducer NEWSBASE
face plates),” he says. The basic design is similar to a normal car engine, except that in this case the crankshaft is driven by a servo motor. Servo motor speeds can be controlled simply and precisely, as the drives incorporate positional feedback via encoders or resolvers installed within the motor. This makes different modes such as constant speed, linear ramps, non-linear ramps and steppedramp frequency sweeps all possible, either manually or pre-programmed. Using such accurately controlled AC servo motors has a major benefit to performance. “Since [they] have a high and uniform torque from start-up (0 rpm) up to their rated speed, this allows us to eliminate the multiple resonances that are inherent in other designs,” Andersen explains. Moreover, GPUSA’s vibrator incorporates the ability to adjust the displacement of the transducer face plate with frequency in order to maintain a relatively constant Sound Pressure Level (SPL). The company has also developed a way to vary the stroke of the connecting rods dynamically using a separate lead screw and motor assembly, and the design incorporates an internal pressure management system that minimises performance variation with depth. The transducer plates are enclosed within a highperformance rubber tyre for protection, and the vibrator system as a whole is controlled via the latest touchscreen computer technology combined with programmable logic. “Ours is the simplest and most efficient method, and I believe most experts realise it is the only technology capable of meeting the JIP specifications,” Andersen says. Whatever the outcome, the prospects for more environmentally friendly options are bright – and the benefits for operators could be great too. As Burnett remarked: “We anticipate that with a marine vibrator having a smaller environmental footprint, it’s going to be easier to get access and less expensive overall to run these things… The majors want the technology to be developed and to get far enough along so the industry will adopt these measures.” n
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PET projects
December 2016
As the PETGAS JIP moves into its third phase, Professor Quentin Fisher explains the aims and technology behind a comprehensive database focused on characterising the world’s tight gas reservoirs
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N Europe at least, tight gas has been something of a footnote in the wider unconventionals boom. Despite significant resources, much attention has moved towards shale gas. For Professor Quentin Fisher, this is a missed opportunity. “I often come across logs from tight gas sandstone reservoirs where the gas-filled porosity and permeability are much higher than for shale plays – I don’t understand why we’ve gone straight to shale gas when there are a lot of tight gas reservoirs,” he tells InnovOil, speaking by phone from his office at the University of Leeds. This reluctance is perhaps partly because the physical properties of these reservoirs remain something of a mystery to much of the industry. Until a few years ago, very little was understood about the multiphase flow properties of these tight gas sandstones. Moreover, even when they could be characterised, profitability might be marginal. But the resources are there. In October, the Oil and Gas Authority’s Southern North Sea area manager, Eric Marston, noted: “We estimate another 3.7 trillion cubic feet [105 bcm] of gas remains from current assets and, potentially, another 5 tcf [142 bcm] combined from further drilling in current fields and discovered undeveloped new fields.” With the correct identification, characterisation and equipment, the development of tight gas could be transformative in the North Sea and further afield. Around 2005, Fisher set up a lab at the University’s University of Leeds’ Centre for Integrated Petroleum Geoscience (CiPEG) to measure and understand the relative permeability and capillary pressures of fault rocks that can result in reservoir compartmentalisation. However, only a few of the major firms were using this data. “We were studying the multiphase flow properties of faults for 2-3 years but found that the industry wasn’t really using the results. Only one or two of the biggest companies really had the in-house capability
to use the data,” he explains. “It coincided with a trip I had to Oman about 8 years ago to present some results on a consultancy project I was doing on fault seal but while there it became pretty obvious that we didn’t really have any really good petrophysical property data from tight gas sands.” His observation coincided with a call for proposals for the study of tight gas sands, put out by the UK’s Industry Technology Facilitator (ITF). Fisher’s idea was to develop a detailed database of the petrophysical properties of these gas-bearing sandstones, which could be used to improve wire-line log data interpretations and enable faster characterisation of these reservoirs. This socalled “Atlas of the Petrophysical Properties of Tight Gas Sands” would include detailed descriptions of the properties of individual samples, covering everything from porosity and mercury-injection characteristics to diagenetic history. Having secured the support of 6 major sponsors – including BP, BG Group, San Leon and Wintershall – in 2008 the proposal was formalised as the Petrophysics of Tight Gas Sandstone Reservoirs – or PETGAS joint industry project (JIP). Heads in the sand Phase I of the JIP saw the team collect 25 tight gas reservoir samples from each of the sponsors and set to work. The result was, as Fisher describes, “a pretty comprehensive database” in which every sample was subjected to detailed analysis. “We measured porosity, permeability as a function of stress, NMR T2, electrical resistivity, ultrasonic velocities, mercury injection capillary pressure, BET, and then integrated these results with microstructural data collected using a scanning electron microscope,” he adds. Around 50% of these samples were from the Rotliegend of Europe (UK, Netherlands and Poland), with the remainder spread across Jurassic, Triassic and Carboniferous NEWSBASE
reservoirs from Europe, Argentina, Oman, North America and Ukraine. For around 50 samples, the team conducted even more detailed special core analysis (SCAL), delving into their capillary pressures, electrical resistivity as a function of brine saturation, gas relative permeability, and more. Over the next four years Fisher and his researchers assembled these results into a functional database, using it to inform more fundamental understandings of some of the key properties – for instance, what controlled the relationships between porosity and permeability. In 2012 the JIP moved on to its second phase, and did so with largely the same sponsors. This enabled the database to continue to grow and to become more sophisticated. As it did, more data and supporting information was able to be added, including more wireline log data and core photographs. The database became too big to handle using existing software tools, so Fisher’s group developed an in-house data visualisation tool,
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Comparison between Hg injection curves obtained using the traditional MICP (unconfined) and the new stressed Hg porosimeter for sample AUR1-20
Stressed Hgporosimeter in the Wolfson multiphase flow laboratory
known as PETMiner. As a repository for all of the assembled data – wirelines logs, image data spreadsheets and more – Fisher says that the software is already being used by several companies but that the group intends to add a lot more functionality before releasing a fully commercial version next year, via a spin-off company from the University of Leeds. A key aim will be to add data-mining capabilities to help identify analogues on the database from easy-to-obtain information, such as the microstructure of cuttings. He added that: “We have already demonstrated that we can provide good estimates of reservoir quality based on the microstructural analysis of cuttings even from very old wells. This provides unique data to allow operators to cheaply reappraise prospects that have been abandoned for being too tight. Our aim is not to develop functionality within PETminer that would allow the non-expert to complete such analysis.” Although assembly of the system has been long, in practice these tools have significant
advantages for the industry. “It’s really obvious when people drilled wells, even if they took core and tested them, that it is really difficult to interpret without a good knowledge of the rock properties, and some of these laboratory tests take so long that you couldn’t get that knowledge within one or two years,” Fisher says. “What we wanted to do was to provide it much quicker, and while it wouldn’t have the same accuracy as really detailed tests, it could give them a good ballpark idea.” “If we can get even a small sample we can put it under the electron microscope, compare it to everything else in the database, identify analogues and that allows us to provide companies with broad estimates of their reservoir properties really, really quickly – within a less than a week of getting a sample – and a lot more cheaply,” he says. Even with cuttings, the information already on file can help users estimate porosity and permeability relationships. When used alongside wireline log data, these can be used to infer potential flow rates. NEWSBASE
Comparison between Hg injection curves obtained using the traditional MICP (unconfined) and the new stressed Hg porosimeter for sample AUR1-3. If this is useful for reservoirs which obey general rules, it is even more valuable for the exceptions. “It allows you to explain really unusual reservoir behaviour,” he notes. “For instance: If you drill and frack a well and you get lots of water and no gas, you can use the dataset to try and understand why that it is. You can then make decisions as to whether you should walk away or try to sidetrack the well.” Mercurial strategy One of the most interesting innovations to come from the second phase of project is a very high-spec piece of equipment for conducting mercury injection capillary porosimetry (MICP) analysis. MICP – or Hg-injection – testing is routinely used for determining capillary pressure and may also be used to estimate permeability. The capillary data enables operators to predict gas saturation as a function of the height of above the free-water level. Yet accurate prediction using these measurements can be problematic. Fisher
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December 2016
explains: “If you measure sample permeability under ambient stress conditions – that’s what the industry would call routine core analysis – the permeability can be two orders of magnitude higher than measured under insitu stress conditions, just because samples get damaged when you bring to the surface, they cool and they get microcracks; it seemed very likely the same would be true for mercury injection analysis.” The only response, of course, was to design a new instrument which could perform the test at in-situ conditions. The high interfacial tension of mercury means that it is often injected into rocks at 60,000 psi, meaning the apparatus has to confine samples at even higher pressures – up to 100,000 psi. This required some substantial engineering. However, when the firm contracted to build the components went into administration, much of the build and testing was left up to the University itself with a state-of-the-art control system for the instrument, designed and written by Adam Schiffer of infologic. Nevertheless, the finished equipment has produced some excellent results – and which are often “radically different” to the assumptions made with previous MICP tests. “We can put samples under confining pressures up to 100,000 psi and inject mercury at up to 64,000 psi, and the results from that are looking really interesting.” In this regard, the PETGAS project has managed something fairly unique. “Various other core analysis companies have said that they were going try to build something similar but none of them seem to have done so as far as I can tell, especially under those pressures,” Fisher adds. This increased accuracy could have profound effects in terms of how the industry approaches and estimates tight gas development. Fisher explains: “In some places, such as in Oman, [we found] MICP tests are very good at predicting capillary pressure, but in other places the results can be totally misleading. If you applied them to try to work out the saturation of gas in a reservoir containing large concentrations of delicate clays such as illite, you’d really overestimate the gas in place [GIP], and that would affect economic decisions.” Triple threat With the conclusion of PETGAS II in July 2016, the team wasted little time before the launch of PETGAS III this autumn. Sponsors Energie Beheer Nederland (EBN) and PDO
InnovOil
are already on board, allowing the team to extend the database by a further 15 samples per sponsor, and continue SCAL test work on a further seven samples per sponsor. (For any latecomers, the JIP is still open to new entrants too). The goal, as with Phase 2, is also to improve the information and detail available through PETMiner. “A really big push we’ve had is to integrate all the measurements we make with wireline log data to improve the interpretation of those logs,” Fisher says. In the current database, more than half the wireline logs also have corresponding production rate data, adding further weight to the database’s predictive power. “We think that we can interpret the wireline logs and then estimate the production far better now, thanks to this project.” That is a vital step forward, given the uncertain economic returns of many tight gas developments. “We have to get away from traditional ways of trying to predict reservoir quality. With conventional reservoirs, you tend to pay particular attention to calculating the hydrocarbons in place and less attention to estimating flow rates because they are clearly going to be high. But when you get to unconventionals you really have to think about production rates because they can be so slow that the prospect is uneconomic to produce,” Fisher explains. Doing so will be key to projects in areas like Oman, which in addition to being an “EOR playground”, as Fisher says, have ambitious long-term strategies for tight gas development across some challenging formations. Closer to home, the involvement of EBN in particular signals interest in the potential of North Sea tight gas, and the UK’s Oil and Gas Authority is making similar noise. Although full development could be some years away, Fisher is optimistic about its prospects. “There’s a lot offshore, and if you can get the costs down, there are no [land conflicts] to speak NEWSBASE
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of… With a lot of fracking-capable vessels we might be able to really hammer down the costs, and really open things up.” That precedent has already propelled the sector to dizzying heights in the US. With the right support, tight gas could see a similar transformation. “It’s always been a mantra in unconventionals to sort of ‘learn to lean’ – putting loads of technology research at the front-end so you can cut costs when you get to the production phase,” Fisher opines. Whatever the eventual outcome, the information gleaned by the PETGAS project is sure to be an invaluable tool for decades to come. n Contact: Professor Quentin Fisher (below) Email: q.fisher@see.leeds.ac.uk Web: http://petgas.leeds.ac.uk/
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December 2016
Kongsberg, Automated Ships aim for unmanned operations
Norwegian-led project will see autonomous ships deployed and tested in Trondheim fjord
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S InnovOil recently reported, the age of unmanned and autonomous ships is already upon us. With no technical limitations to speak of, the industry is simply waiting for regulation to catch up – not that this seems to be stopping a few of the bolder marine firms. Early November saw UK-based Automated Ships sign a Memorandum of Understanding (MoU) with Norway’s Kongsberg Maritime to build the Hrönn – an innovation the two have described as “the world’s first unmanned and fully-automated vessel for offshore operations.” The agreement will see Automated Ships contract the ship in January 2017 and will act as project manager and ship-owner, while design and construction carried out in Norway in collaboration with shipyard Fjellstrand and Kongsberg. Given the nascent stage of regulation, certification body DNV GL and the Norwegian Maritime Authority (NMA) will then oversee sea trials in Norway’s Trondheim fjord – a newly designated test bed for automated vessels and technologies. “Increased automation combined with remote monitoring and control is an inevitable trend and has the potential to create safer and more efficient transport
and operations at sea. This may lead to unmanned ships, as in this case, and the technologies involved also have the potential to improve the safety and efficiency of manned ships in the form of increased decision support and operational assistance” said DNV GL Maritime Research head, Bjørn Johan Vartdal commented. The announcement marks rapid progress for the industry. Having been announced in March 2016 as part of the Norwegian government’s National Transport Plan, the Trondheim testbed was inaugurated in September. It was chosen largely because of its low traffic, but also its proximity to several major academic and research organisations, including the Ocean Space Centre, the Norwegian University of Science and Technology’s (NTNU) Center for Autonomous Operations and Services (AMOS), and the Norwegian Marine Technology Research Institute (MARINTEK). Hrönn the go According to the developers, Hrönn will be a light-duty, offshore utility ship aimed to serve the energy, scientific and fish-farming industries. In addition to cargo delivery and general support, it will also be capable NEWSBASE
of ROV and AUV launch and recovery and suitable for use as a standby vessel. The design also allows for the potential outfitting of firefighting equipment, in support of manned firefighting ships. Kongsberg did not respond to a request for more information regarding the ship’s design and specifications. Initially, Hrönn will be piloted remotely – what Kongsberg terms Man-in-the-Loop Control mode – but will move towards full autonomy as algorithms are developed during these remote operations. Much of the automation is being tackled by Kongsberg, which will provide all systems for dynamic positioning (DPS) and navigation, satellite and position reference, marine automation and communication. The vessel control systems, including the company’s K-Pos dynamic positioning, K-Chief automation and K-Bridge ECDIS, will be replicated at an Onshore Control Centre, enabling remote operation. “The Hrönn is an incredible ship and a great example of KONGSBERG’s commitment to developing autonomous and unmanned vessels. We are involved in several major projects in this field including AUTOSEA, which focuses on integrated sensor technology and fusion,
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Artist’s impression of the Hrönn vessel
and automated collision avoidance systems,” added Kongsberg Maritime , EVP global sales & marketing Stene Førsund. Meanwhile, Automated Ships says it is in discussion with “several end-users” who it hopes will become early-adopters, and who will establish a base-rate for the cost of operations.
The company’s managing director, Brett A. Phaneuf stated that: “The advantages of unmanned ships are manifold, but primarily centre on the safe guarding of life and reduction in the cost of production and operations; removing people from the hazardous environment of at-sea operations and re-employing them on-shore to monitor
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and operate robotic vessels remotely, along with the significantly decreased cost in constructing ships, will revolutionise the marine industry. Automated Ships Ltd will be at the forefront of that revolution, along with its many Norwegian partners.” Although sea trials these vessel are perhaps are year or two out, autonomous ships are about to make serious waves in the maritime industry. Although the project’s participants are keen for Hrönn to be the first fully autonomous ship to begin serving the industry, others are certain to follow in its wake. n
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Medical tech makes particles smarter
December 2016
Ros Davidson speaks with researchers at University of Texas’ Advanced Energy Consortium about how medical technologies are enabling “smart particles” and an MRI-like reservoir scanner
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ERHAPS now more than ever, there is a concerted push from the oil and gas industry to take in new technologies from other industrial sectors. In one such application, medical expertise is being transferred to the oilfield in new research coordinated by the University of Texas’ Bureau of Economic Geology in Austin. The researchers, backed by oil companies and including scientists at a number of other global universities, are looking to adapt smart particles the size of a grain of sand that could be used, for example, during fracking or in wellbore cement. They are also researching underground MRI-like imaging techniques which would allow them to “light up” a frack job, and developing a method of payload delivery using nanovehicles that could act like a time-release medication or release their contents when a certain chemical reaction takes place within the reservoir. Why not? According to chemical engineer Jay Kipper and project manager Mohsen Ahmadian
of the University’s Advanced Energy Consortium (AEC), these smart particles are computer chips about the size of a grain of sand. Their size and construction allows drillers to mix and inject them as part of conventional fracking fluid. “If you have smart dust and can throw it into a reservoir, you can do smarter things such as recover more hydrocarbons,” Kipper explains to InnovOil. The nanomaterial sensors, once injected, could measure temperature, pressure and chemical composition. What began as blue-sky research a few years ago has now progressed to the point at which lab and field tests are now occurring. The idea for the particles, originally came when Kipper and a colleague (AEC director Scott Tinker) attended a medical conference and heard about nanosensors which could be introduced into the human body: “We looked at each other and said, why not in the earth?” The scaled-down semiconductor sensors contain a battery, coding and flash memory, and measure pH, temperature, pressure and
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resistivity. The base is an integrated silicon transistor chip, while the battery is based on a proprietary chemistry that can withstand temperatures of about 125°C and pressure up to 7,500 psi. All of this is housed in an alloy package. The first generation being developed measure 8mm3 in size, but the team expects the next generation to be further miniaturised down to 1mm3, says Ahmadian. The particles could be injected into a fracture network along with the frack fluid, or they could be introduced via coil-tubing or tethers. The current particles would be able to take about 1,000 measurements during the lifetime of a battery, allowing for several deployments over a period of weeks. The battery can also be put to sleep to lengthen the time available on one charge. If the devices are used as a ‘smart
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Bottom left: One AEC concept design for reservoir imaging using a contrast medium
proppant’, they would return to the surface in produced fluids, and would then be read and recharged wirelessly. Currently, they do not have the capability for communication while downhole, but the AEC is researching ways that this could be done. Likewise, if used in cement, they would remain in place over the well lifetime and could communicate information regarding cement integrity. However, this would require a different read-out mechanism and way of recharging – another area the team is exploring. Research remains in the development phase, although laboratory testing has now been concluded, and field testing will occur within the next couple of months in a wellbore in France. So far, the cost of the smart dust is relatively high, but when produced in volume, Ahmadian believes that it will become pennies per device.
Even so, the cost is justified in the technology’s ability to offer data and information that was previously unavailable. “Without smart particles, you’re not currently getting those readings,” Kipper says. Contrast agents Separate research is also being done on producing an MRI-like reading within a fracture network. A contrast agent is used so that an area of interest can be highlighted and analysed. “We can do a smarter frack job,” says Kipper. “It’s like having a set of eyes downhole.” The researchers say that this could be used to answer questions in planning stages – such as where a fracture should occur – or in post-frack analysis to determine where it did occur. Carbon-based conductive materials and iron oxide-based magnetic materials NEWSBASE
are used. A transmitter in the injection well would then pass a signal through the reservoir (and contrast medium) to a receiver array in the production well, producing an image in a manner not unlike an MRI machine. The contrast agents currently cost a few cents per pound, and should also become cheaper as the technique develops. The technique has been demonstrated in the laboratory with computer modelling, and a pilot study is currently being conducted in an oilfield not far from the university campus. Partial field results have been produced and, according to the team, so far they look very good and are in line with expectations. In fact, results were published last year from a small-scale frack job, and the team plans to look at mapping concepts for hydraulic fracturing, waterflooding, Enhanced oil recovery (EOR), and interwell reservoir characterisation applications. In a third area of research based on ideas borrowed from medical applications, payload could be delivered precisely to an area of interest in a wellbore or in reservoir. Material for acid stimulation, for example, could be encapsulated so that the wellbore is protected and corrosion is reduced. The capsule could then be time-released, or it could release its content when a controlled or known chemical reaction takes place. EOR materials could thus be delivered highly accurately using this method. For example, surfactants, detergents or polymers could be delivered to block a highpermeability zone, so that fluids are diverted to a low permeability zone. With a number of very promising pilots on the horizon or already underway, the AEC is all set for a busy 2017 – a year which will hopefully bring even more opportunities to ask – “Why not in the earth?” n
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December 2016
Kashagan begins commercial production Output at Kazakh megaproject rises above 75,000bpd
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ASHAGAN, Kazakhstan’s largest hydrocarbon deposit, is now producing oil in commercial quantities, Energy Minister Kanat Bozumbayev said on November 21. Speaking to members of the Kazakh parliament, Bozumbayev said that North Caspian Operating Co. (NCOC), the consortium that is developing the field, had brought output levels up to the commercial threshold of 75,000 bpd on November 1. He also indicated that yields had remained at or above this level since the beginning of the month. NCOC subsequently confirmed the minister’s statements. “We confirm today’s announcement of the Ministry of Energy of the Republic of Kazakhstan that commercial production has begun at the Kashagan field in the Caspian Sea,” the consortium said on November 21. According to previous reports, NCOC extracted around 201,000 tonnes (nearly 1.7 million barrels) of crude in October, its
first full month of development operations. This put daily output levels at approximately 52,600 bpd. According to Bozumbayev, since Kashagan began test production on September 28, it has yielded about 500,000 tonnes (3.8 million barrels) of crude. The field is on track to produce up to 1.1 million tonnes (8.36 million barrels) of oil this year, and output will rise to 4-8 million tonnes (30.4-60.8 million barrels, or 83,288166,575 bpd) in 2017, he said. The minister also recalled that NCOC had delivered its first cargo of crude from Kashagan on October 14. On the same day, he said, the cargo was loaded into the pipeline system of state-owned KazTransOil (KTO) for transfer to the export link operated by the Caspian Pipeline Consortium (CPC). Kashagan, which lies in the north Caspian Sea, contains 9-13 billion barrels of oil in recoverable reserves and more than 1 tcm of gas. NEWSBASE
Most of the crude extracted from the field will be exported via the CPC link and other overland pipelines, while most of the gas will be reserved for domestic consumption. NCOC includes KMG, Kazakhstan’s national oil company (NOC), as well as Eni (Italy), ExxonMobil (US), Royal Dutch Shell (UK/Netherlands), Total (France), Inpex (Japan) and China National Petroleum Corp. (CNPC). The consortium had previously been known as Agip KCO, but it was reorganised in 2008 after technical problems and cost overruns prevented then-operator Eni from bringing the field on line by 2005 as pledged. NCOC finally began production in September 2013 but suspended operations just a few weeks later, following the discovery of gas leaks in offshore pipeline networks. Since then, NCOC has rebuilt its pipelines so that the network can withstand sulphide stress corrosion from the sour crude in Kashagan’s reservoir. (The oil must be treated prior to export). n
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EMEC joins FORCE in corrosive thinking
UK-based Marine Energy Centre launches JIP with Canadian counterpart to study underwater coatings on both sides of the Atlantic
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ARINE coatings must survive and protect against some of the toughest working environments. Where better to test them, then, than in some of the areas of strongest tides and waves on either side of the Atlantic? A new joint industry project (JIP) was recently announced between coatings manufacturer Whitford, the European Marine Energy Centre (EMEC) and the Fundy Ocean Research Center for Energy (FORCE). Using test sites at the respective facilities in Orkney and Nova Scotia, Whitford will compare how its coatings perform in each environment. According to a statement from EMEC, the project has its roots in a joint declaration made in 2011 by the then Prime Ministers of the UK and Canada, David Cameron and Stephen Harper. This saw the two pledge to work together to increase growth, trade and innovation, which in turn led Innovate UK and the Offshore Energy Research Association of Nova Scotia (OERA) to set up the trans-Atlantic project, partnering EMEC and FORCE to work on the InSTREAM project, which tested sensor technology. Since then, the two have shared knowledge and results gained from numerous tidal and wave energy tests. Indeed, during a recent visit to Nova Scotia, EMEC managing Neil Kermode noted that he might have an application relevant to the FORCE project. Kermode explained: “Corrosion and other associated issues are a big challenge for wave and tidal energy technologies given that devices could be deployed at sea for years at a time. During discussions we realised that the marine conditions experienced at FORCE’s test site in Nova Scotia are very different from what we are seeing across the pond at EMEC, in Orkney. So the inclusion of a technology testing programme with us will provide a different experience if they then decide to deploy in Canada, or vice versa.” Bay watch The Bay of Fundy is one of the most extreme tidal environments in which to test these coatings. With 14 billion tonnes of water
Whitford coating trials at Stromness Harbour (Credit: EMEC)
moved every tide, at speeds in excess of 20km per hour, they encounter far more than the oxidation and marine growth which might be common to oil and gas infrastructure. FORCE general manager Tony Wright commented: “Working in the world’s highest tides is a challenge, but also an opportunity for technologies to meet the ultimate test of durability: the ‘Fundy Standard.’ EMEC and FORCE are both working to advance the marine renewable energy sector responsibly and economically, and opportunities like this – to share research, knowledge and technology – [are] critical to that work.” Whitford and EMEC have been working together since 2014, conducting tests on the performance of coatings in the dynamic and volatile environments found at EMEC’s test sites in Orkney. Whitford’s Gareth Berry noted that in addition to the results, it may help qualify the company’s coatings for use NEWSBASE
in the Canadian market: “The Canadian market is really big due to the scale of the marine energy resource and we are keen to get our product tested and proven there too.” Kermode is confident that there will be further opportunities to expand the project further to get a full understanding how new materials behave at different sites across the globe – a move which could be beneficial for renewables and the marine sector as a whole. “The corrosion and other behaviour experienced in the northern hemisphere will be different from that in the south, and it’ll be different in the tropics compared to temperate areas. The potential for marine energy, however, is global, and technology developers will need to be prepared for this,” he stated. n Contact:
Email: info@emec.org.uk Web: www.emec.org.uk
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AkerBP starts up Viper and Kobra Aker BP announces the start-up of production from Viper-Kobra, which is tied back to the Alvheim FPSO. The project is developed on time and within budget. “The Viper-Kobra project is developed on time, on budget and is a small, but important project for Aker BP. Viper-Kobra leverages on the existing infrastructure in the Alvheim area, thus ensuring maximum utilization of the adjacent resources and will contribute to maintain the Alvheim production at a high level”, says Geir Solli, SVP Operation at Aker BP. The development costs for Viper-Kobra is approximately NOK 1.8 billion, including the drilling of two wells, subsea installations, pipelines and hook-up. Viper-Kobra consists of two separate discoveries, were Kobra was discovered in 1997, production licence 203, and Viper, production licence 203, in 2009. ViperKobra is not a separate field, but constitutes part of the Alvheim field. Thus, the development is included in the PDO for Alvheim, as are the other structures in the area. The development comprises of a new subsea installation with a pipeline tied into the Volund manifold. The four well slots are designated for
one well from Viper and one from Kobra, in addition to two well slots intended for potential future wells in the area. The two reservoirs contain approximately 4 million barrels of recoverable oil each. Including some gas, total recoverable reserves are estimated at 9 million barrels of oil equivalents. The estimated output of the two wells is planned to an average initial daily rate of 15 000 barrels of oil equivalents. The distribution of ownership interests corresponds to that of the Alvheim licence; Aker BP, operator, 65 per cent, ConocoPhillips 20 per cent and Lundin Norway with a 15 per cent interest. AKERBP
Technip introduces new diving support vessel Deep Explorer Technip’s latest newbuild, the diving support vessel (DSV) Deep Explorer, was officially
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named on Saturday November 12, in Norway. The traditional naming ceremony was held at VARD’s Langsten shipyard. The vessel godmother was Heidi Brovoll-Bø, wife of Knut Bø, President of Technip’s North Sea Canada region. The vessel hull was built by Vard Tulcea shipyard in Romania, and then towed to Vard Langsten in Norway for equipment outfitting and commissioning. The vessel features a state-of-the-art 24-man twin bell saturated dive system rated to 350m. The dive system was designed, built and commissioned by JFD, part of James Fisher and Sons plc. Deep Explorer is a DP3 class DSV, purposedesigned and certified for subsea projects in the demanding North Sea Canada market. She is the most modern and versatile DSV in the world, thanks to her latest technology diving control system, 400 Te box boom crane, large deck area, working moonpool and work-class ROVs*. Deep Explorer is capable of working globally on diving and subsea construction projects, even in extreme weather conditions. She will commence operational duties in 2017. Bruno Faure, Technip’s Senior Vice President Subsea Projects and Operations, said: “This event marks an important milestone in this three-year project to design, build and deliver this impressive fantastic new ship. We are proud to welcome the Deep Explorer, an impressive key asset for the Technip fleet and for our clients. My sincere thanks to all those in
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expected to join RAPID as a 50% joint venture partner once Petronas Chemicals takes its FID in December. Aramco, which has also entered downstream ventures in China, South Korea and Japan, is likely to capture upside from the project ahead of an IPO anticipated for 2018. State-owned Petronas, meanwhile, will be able to spread costs with Aramco while it completes up to 50 billion ringgit (US$11.55 billion) worth of spending cuts planned by 2020. In June, for instance, reports suggested the pair were jointly scoping out US$7 billion worth of financing from banks and lending institutions to help fund two projects worth US$12 billion. Edited by Andrew Kemp andrew.kemp@newsbase.com
Inpex finishes Ichthys subsea pipeline Technip and our partner companies who have contributed to this successful project.” Yard Director and Senior Vice President at Vard Langsten, Dag Vikestrand, commented: “It has been a great honour for us in VARD to be a part of this exciting project. Deep Explorer represents a technological quantum leap, thanks to the excellent teamwork between Technip, JFD and VARD. The knowledge, skills and experience of all parties involved have been key factors in achieving the design and build of this impressive vessel.” Technip operates a leading-edge fleet of 18 vessels (with another 4 under construction) specialized in pipeline installation and subsea construction on all continents. TECHNIP
Petronas awards refinery EPCC contract PETRONAS Chemicals has awarded a US$328 million engineering, procurement, construction and commissioning (EPCC) contract to a consortium led by Italian vendor Tecnimont for the Pengerang refinery and petrochemical integrated development (RAPID) project. The consortium, which also includes Beijingbased China Huanqiu, will deliver services for
RAPID’s 400,000-tonne polypropylene unit from November 10 until July 9, 2019. Earlier this month, DuPont was selected to provide three scrubbers at RAPID, each with reverse jet stages designed to cope with inlet temperatures of up to 1,200 degrees Celsius. On November 3, Petronas Chemicals said RAPID was on schedule for launch in 2019, while reporting a 1.25 billion ringgit (US$289.4 million) third-quarter profit, up from 1.22 billion ringgit (US$282.4 million) year on year. Other new petrochemical projects highlighted in the update included an integrated aroma facility and a 2-ethylhexanoic acid plant, both located in Kuantan in Pahang Province. The US$16 billion RAPID project comprises a 300,000 bpd oil refinery and 7.7 million tonne petrochemicals complex with a 3 million tonne steam cracker. It will form part of the Pengerang Integrated Petroleum Complex (PIPC), which encompasses refineries, naphtha crackers, petrochemicals and an LNG import terminal. The development, Malaysia’s largest liquidbased greenfield project, was twice delayed because of difficulties rehoming local residents, and was eventually pushed back last year to mid-2019 in response to weak oil prices. In light of the industry depression, Petrochem decided to review some of RAPID’s engineering, procurement and construction (EPC) contracts and nix a US$1.3 billion elastomer component. Saudi Aramco is widely NEWSBASE
INPEX’S subsea pipeline from the 8.4 million tonne per year Ichthys LNG project is ready for first gas after the Japanese company welded its two pipe sections together at Darwin in Australia’s Northern Territory. Connecting the 882-km offshore and 8-km onshore portions means the pipeline is now capable of delivering gas to Inpex’s processing centre at Bladin Point. Construction of the 42inch (1.07-metre) pipeline, which is the world’s third longest subsea pipe, involved 73,000 individual segments, each weighing around 26 tonnes. It will target 12.8 tcf of gas (362.5 bcm) reserves contained at the relatively shallowwater Ichthys gas field, plus 527 million barrels of condensate. Inpex owns a 62.245% stake in the Ichthys LNG consortium alongside Total E&P Australia with a 30% interest. Taiwan’s CPC holds 2.625%, while Japanese utilities Tokyo Gas, Kansai Electric Power, JERA and Toho Gas own 1.575%, 1.2%, 0.735% and 0.42% respectively. Ichthys will launch in the third quarter of 2019, when liquefaction commences from two 4.2 million tonne per year trains that can also produce 1.6 million tonnes of LPG and 100,000 bpd of condensate. Inpex remains confident of the project’s success despite the A$200 billion (US$151.2 billion) investment that has brought a raft of new Australian LNG capacity into an oversupplied global market since 2014. The Tokyo-based firm has booked 70% of its output with Japanese offtakers and is eyeing
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• Challenge 5 – Maximising productivity from a well Malcolm Banks, Well Construction Solution Centre Manager at the Oil & Gas Technology Centre said: “We’re delighted to be hosting this exciting event. It will bring together oil and gas operators, service companies and technology specialists from the oil and gas sector and other industries to explore how new and existing technologies can transform the way we drill hydrocarbon wells, increasing efficiency and reducing costs. Ideas generated at the event will be collated into a report which will be made freely available and be used in developing a programme of projects. Attendance at this hackathon is by invitation only and there are a limited number of spaces. To register interest, visit the ITF website. OGA
a slice of the 25 million tonnes per year of additional demand that it has predicted will emerge from 2020 onwards. Ichthys has 15-year sales and purchase agreements with firms including CPC (1.75 million tonnes), Total (1.8 million tonnes), and a consortium consisting of Tokyo Electric Power Co. (TEPCO) and Tokyo Gas (4 million tonnes). “Even looking beyond the 15-year sales and purchase agreements now in place, [long-run LNG demand growth in Asia-Pacific] will mean that there will continue to be opportunities,” Inpex CEO Toshiaki Kitamura told the Sydney Morning Herald in April. Indeed, Inpex may take heart from thirdquarter figures unveiled by other Australian LNG producers in recent months. Oil Search and Santos reported LNG prices had risen by 23% and 10% quarter on quarter to US$6.44 per mmBtu (US$178.13 per 1,000 cubic metres) and US$5.72 per mmBtu (US$158.22 per 1,000 cubic metres) respectively, and with oil-indexed contracts the industry norm, Inpex could benefit should benchmarks stage a recovery in 2017. Edited by Andrew Kemp andrew.kemp@newsbase.com
OGA launches well-tech hackathon The Oil and Gas Authority (OGA) is holding a hackathon to identify new technology and practices which can reduce the cost of well
construction on the UK Continental Shelf (UKCS). Jointly driven by the Technology Leadership Board Workgroup, ITF and the OGA, the focus of the event will be to highlight challenges associated with well construction and to use the day as a platform for supply companies, including developers, to work with industry to identify innovative solutions. It is the first of a series of hackathons to take place at the newly established Oil & Gas Technology Centre. Margaret Copland, Senior Wells and Technology Manager at the OGA, said: “Well construction currently accounts for approximately half of field development costs. By hosting this hackathon, we particularly want to identify technologies that can be adapted from other industries and new, innovative ideas that could transform how wells are constructed. “New technologies and efficient practices have the power to deliver significant savings in this area. This could allow additional marginal and mature field reserves to be developed and extend the life of existing infrastructure to maximise economic recovery for the whole UKCS.” The format for the day will comprise a number of themed stations with additional support from facilitators, also known as ‘pioneering practitioners’, who will capture the ideas at each topic station. • Challenge 1 – Rock cutting and Transportation • Challenge 2 – Borehole Stability and Formation Pressure • Challenge 3 – Wellbore Isolation • Challenge 4 – Materials for Downhole Equipment NEWSBASE
Canada’s Genoil moves into Chechnya CANADIAN engineering firm Genoil has signed a letter of intent (LoI) to pursue several integrated projects in Chechnya worth US$15 billion, the Toronto-based company announced on November 9. The agreement with local producer Grozneft is for the development of oil and gas fields as well as the construction of clean technology upgraders, refineries and pipelines, Genoil said in a statement. The investment is part of US$50 billion in capital expenditure earmarked for projects in Russia, the company added. In total, the integrated projects are expected to yield 3.5 million bpd of refined oil products. The publicly listed firm said that it would form a consortium of unnamed Chinese engineering and oil services companies to support these schemes, which will employ Genoil’s hydroconversion process for desulphurisation. “The negotiation of this LoI marks an important milestone for Genoil, demonstrating that we can act as a service provider as well as a technology provider,” said the company’s vice president, Thomas Bugg. Grozneft chairman Andrey Gusak told Russian daily Vedomosti last week that a 3-6 million tonne per year (60,000-120,000 bpd) refinery would be built in Chechnya, adding that a construction site had already been selected. Genoil may also undertake work at the Mendeleev refinery in Yaroslavl as well as upstream projects
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elsewhere in Russia, although he did not reveal the identity of any fields. However, Vedomosti quoted a source at the Ministry of Economic Development as saying that no documents relating to the projects had been received from Grozneft or Genoil to date. Gusak said that Grozneft was set up in April this year to act as a local partner for international and other investors. The aim was to help spur oil production and refining development in Chechnya following decades of decline. Oil giant Rosneft and local producer Grozneftegas produced 9,000 bpd of crude last year, down from a peak of 602,000 bpd that was extracted in the republic in the 1970s. The latest LoI builds on a similar agreement sealed between Genoil and Beijing Petrochemical Engineering earlier this year. In April, the pair received an LoI from an unnamed Chinese lender for an upgrading project in the Middle East. The project could eventually yield 3.5 million bpd of refining capacity for a total investment of up to US$50 billion. Both schemes will produce fuels to be exported to buyers in China on long-term contracts of up to 30 years’ duration. Edited by Joe Murphy josephm@newsbase.com
Floating LNG surges ahead FLOATING LNG (FLNG) technology has the potential to shake up the LNG industry if initial projects perform well, according to a new report by the Oxford Institute of Energy Studies. Compared to onshore LNG plants, FLNG vessels offer many advantages for developing remote offshore gas reserves, including avoiding the need for a subsea pipeline to shore, which helps to reduce costs. FLNG units can also be leased or contracted on a tolling basis, enabling smaller energy companies to compete in the market. “FLNG offers a much higher confidence in meeting the delivery schedule and production date by using a shipyard rather than onshore construction in remote and challenging areas which frequently experience major delays,” the report said. “First production date is critical to project profitability and very important to lenders on financed projects.” Liquefaction-only FLNG facilities cost typically US$700-800 for each tonne per year of capacity, similar to onshore plants being built in the US, the Oxford Institute report noted. Another disadvantage to FLNG is that it can only be used in benign ocean conditions
because proven offloading arms only work in up to 2.5 metres of significant wave height. However, cryogenic hoses and concepts that employ tandem loading that have been developed would widen the operating window. Additionally, FLNG reduces opportunities for local content in countries that have labour resource requirements, and low oil indexed and spot LNG prices also threaten FLNG projects. Seven FLNG projects totalling 17 million tonnes per year are currently under construction, with another 17 projects in the planning and pre-engineering stage that could deliver an additional total 55 million tonnes per year. The Exmar-owned Caribbean FLNG project produced the first LNG from a floating unit in October, while the Petronas PFLNG Satu is expected to begin producing LNG before the end of 2016. Edited by Richard Lockhart richardl@newsbase.com
Chinese oil shale project sees first output A Chinese newspaper has reported that a local firm has successfully produced oil shale for the first time in Jilin Province, around 10 years after exploration work began. According to the Jilin Daily, Jilin Unity & Strength Oil Shale Investment Development used “oil shale in-situ retorting technology” to
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tap the resource. This method saw the shale layer heated underground in order to force it to crack, with the resulting natural gas and oil shale pumped to the surface. Once filtered by gauze, the fuel is ready to be used by some engines without the need for further processing, the newspaper added. “Our oil shale project has entered the pilot stage, at which the daily output of a single well’s shale oil can reach 200 kg and more, three times the initial stage,” Jilin’s technical director, whose name was not disclosed, said in an interview with the newspaper. The company says the in-situ method is more efficient and less wasteful than traditional techniques, which usually require for the solid shale to be mined and then heated at the surface. This typically requires large amounts of water. “The oil shale is located deep, the layer is thin and the oil rate is low. It not only can make full use of the resources but also can protect the environment,” Jilin’s project director, Zhao Jinmin, who invented the technology, told the Jilin Daily. Jilin was formerly known as Jilin Shell Oil Shale Development, which was formed in 2006 as a joint partnership with super-major Royal Dutch Shell in an effort to prove the viability of the country’s oil shale deposits under a 2-3 year programme using in-situ retorting. However, Shell withdrew from all 26 oil shale blocks in Jilin in 2008, citing a lack of quality reserves. The blocks were later put up for public tender. Edited by Anna Kachkova annak@newsbase.com
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GE and Maersk Drilling launch data-analytics pilot Today, GE and Maersk Drilling announced a partnership to collaborate on a data analyticdriven pilot project with the aim to increase Maersk’s drilling vessels’ productivity and significantly reduce maintenance costs by up to 20 percent. The two companies have collaborated to deploy SeaStream* Insight, GE’s latest innovation in marine asset performance management, powered by Predix*. The pilot project will be carried out on one of Maersk Drilling’s XLE rigs and will last for 12 months. Currently, the project has reached its first milestone, with data collected from the rig currently being processed and analyzed online. “Digital capability will be one of the key enablers for Maersk Drilling, and we embrace this industrial transition,” said Jesper Hansen, CIO, Maersk Drilling. “We are excited to collaborate with GE who is at the forefront of the digital revolution.” Operational sensor data from critical equipment is connected to a historian, a specialized server that stores the data needed to model the blueprint of the drilling operation. By building this “digital twin,” the digital software can then help compare assets to assets and provide access to vessel performance against the ideal state. Big data is also translated into clear dashboards with a holistic view of a vessel, which can help operators make more informed decisions. Thanks to advanced algorithms and a strong data-processing capability, SeaStream Insight will also be able to predict the future state of critical asset health, therefore spotting inefficiencies or detecting potential failure earlier, up to weeks ahead. Operators are given early warnings to mitigate potential problems in advance, which help reduce unplanned downtime and increase drilling productivity. In addition to enhanced productivity, SeaStream Insight will also allow operators to maintain equipment in a more efficient manner. As the “predictivity” allows transition from prescriptive (calendar-based) to predictive maintenance, it can help reduce excessive maintenance and significant costs for Maersk Drilling. “With the fast-paced changes of globally connected economies and shifting regional opportunities, marine operators need to
transform themselves to be efficient, predictable and nimble. Drawing critical insights from operational data is a crucial first step,” said Tim Schweikert, president and CEO, GE’s Marine Solutions. “With the present period of prolonged energy price instability, we believe data analytics tools provide the right technology that will help the industry going through current downcycle and maintain sustainable growth for the future.” GE
Baker Hughes introduces the next generation of fluids separation technologies Baker Hughes has announced the commercial release of its TRETOLITE™ SNAP fluids separation technologies, designed to help oil and gas operators maintain dry oil and good water quality, while also stabilizing operations and reducing costs—without limiting production— to improve overall profitability. This next generation of chemical solutions includes water clarification and demulsification technologies that deliver improved performance in multiple production applications, including steamassisted gravity drainage (SAGD) facilities, as well as conventional and other unconventional onshore and offshore fields. For SAGD producers, fluids separation is vital to the success of their operations because the recovered water must be clean enough to reuse in the thermal recovery process. The water is used to generate steam for injection into the well to heat the extremely heavy oil. These operators often are forced to compromise
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profitability to get in-spec oil and good quality water. TRETOLITE SNAP technologies help minimize oil-in-water (OIW) levels to improve water quality for reuse, reducing heat exchanger fouling and related equipment cleanout expenses. The new products also help lower basic sediment and water (BS&W) content in the oil to decrease recycling and slop oil trucking, which translates into additional operational efficiencies and cost savings. TRETOLITE SNAP technologies enable SAGD producers to increase profitability by getting a more controlled oil/water interface that improves production volumes and throughput capacity. Operators also experience oil and water separation challenges in other unconventional and conventional onshore and offshore applications where they are required to meet regulatory specifications for both in-spec oil and water disposal/discharge. TRETOLITE SNAP technologies help to more efficiently lower OIW and BS&W levels to ensure regulatory compliance and to minimize oil losses due to high OIW content. Operators may also attain a tighter oil/water interface with these new products, which helps reduce slop oil production and improve overall oil and water separation. In a recent Canada application, a SAGD producer was experiencing heat exchanger fouling that increased operational costs beyond profitable margins. Baker Hughes applied a TRETOLITE SNAP water clarification treatment program, which exceeded the incumbent product’s performance by reducing OIW at the free water knock out by 58 percent and BS&W at the treater by 53 percent. The operator also was able to reduce the generation of skim, slop oil and off-spec recycling streams. Since implementing the TRETOLITE SNAP treatment program, there have been no heat exchanger fouling issues. The operator estimates annual savings of USD 3.8 million by switching to this program. BAKER HUGHES
December 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 on the Marine Autonomous Systems battery project, being led by Steatite, contact mas@steatite.co.uk or visit www.steatite.co.uk To speak with Morgan McCorkle at the Oak Ridge National Laboratory about its work converting CO2 to ethanol, contact Morgan McCorkle via mccorkleml@ornl.gov If you would like to participate in the PETGAS JIP, or have more questions about the project, please contact Professor Quentin Fisher at q.fisher@see.leeds.ac.uk or visit http://petgas.leeds.ac.uk The wee-g could transform how gravimetric surveys are performed. To speak with Dr Giles Hammond and his team about the technology, call +44 (0)141 330 2258 or email giles.hammond@glasgow.ac.uk To enquire about MacGregor’s 3D Motion Compensator unit (3DMC), contact Heli Malkavaara on +358 20 777 4500 or email Macgregor@macgregor.com for more information. You can also contact James Andersen, President & CEO of GPUSA to learn more about seismic marine vibrators at sales@gpusa-ca.com or visit www.gpusa-ca.com
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