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Bringing you the latest innovations in exploration, production and refining Issue 53
DEEPWATER DISCOVERIES Baker Hughes’ DEEPFRAC service Page 9
June 2017
ACTIVATE!
Total’s ARGOS robotics competition Page 22
SECRET WEAPONS
The innovations making new projects possible Page 13-21
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InnovOil
June 2017
page 3
Inside Contacts: Media Director Ryan Stevenson ryans@newsbase.com
Patent problems
6
Electric avenues
7
Thinking deeply
9
Kongsberg and Yara design battery-electric ship
Charles Villiers charlesv@newsbase.com Kevin John kevinj@newsbase.com
Baker Hughes’ DEEPFRAC frac system
Editor Andrew Dykes andrewd@newsbase.com NewsBase Limited Centrum House, 108-114 Dundas Street Edinburgh EH3 5DQ
Tech radar
10
PROJECT INNOVATION
13
Riser and shine
14
The whole FAM
16
Seismic changes
18
CapX costs
21
Robotic revolution
22
Stick that in your pipe
26
Venture time
28
Trelleborg and SubC replace buoyancy modules on a live riser
Enpro’s ESSI FAM system unlocks subsea well development
Phone: +44 (0)131 478 7000 www.newsbase.com www.innovoil.co.uk
BP on seeing through salt
Design: Michael Gill michael@michaelgill.co.uk www.michaelgill.eu
Statoil’s CapX runs into legal trouble
The winners of Total’s ARGOS challenge ™
MIT team develop hydrate-busting coating
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ations Bringing you the latest innov
5
DSME loses partial reliquefaction suit
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A note from the Editor
in exploration, production
and refining June 2017
Issue 53
Inside Statoil Technology Invest
Progress in Vaca Muerta 31 Wintershall and YPF drive down costs
DEEPWATER DISCOVERIES Baker Hughes’ DEEPFRAC service Page 9
Working in the margins
32
News in brief
34
Lloyd’s Register on US marginal development
ACTIVATE!
Total’s ARGOS robotics competition
Page 22
SECRET WEAPONS
The innovations making new projects possible
Page 13-21
Contacts 41 NEWSBASE
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June 2017
InnovOil
page 5
A note from the Editor IF OPEC’s May 25 meeting proved one thing, it was that the cartel may have won the battle, but US tight oil is winning the war. Prices may have slipped as hopes of deeper cuts fizzled, but the real stories are not in the minutes of meetings in Vienna, but in the balance sheets and rig counts of North America. US shale explorers have sought to hedge against further price shocks, and their rig count has more than doubled in the past year, to 703 as of the beginning of May, according to services firm Baker Hughes. Since the count of active rigs in the US reached a low in the middle of 2016, shale producers have added an average of seven units per week, the strongest recovery in 30 years. With prices hovering around US$50 per barrel, drilling budgets for US tight oil producers have risen 10 times faster than the rest of the world. According to a recent report from Barclays, North American shale drillers are intending to lift 2017 outlays by 32%, to US$84 billion, compared with just 3% for international projects. This perhaps explains the recent resurgence in news on tight oil-related technologies. In addition to recognition at OTC this year – Weatherford’s RFID-based AutoFrac system, for example, which won a Spotlight on New Technology award –reports on interesting techniques such as microbial enhanced oil recovery (MEOR) and other production-boosting
methods are becoming more frequent. Conventional producers are also looking to capitalise on the gains made in unconventional markets. Our cover this month features Baker Hughes’ DEEPFRAC system, a ball-activated multistage frac sleeve aimed at enhancing deepwater completions. In this edition, we also take a look at some of the key technologies which have enabled breakthrough project executions. This includes the story behind Trelleborg and SubC Partners’ DBM replacement on a live riser, Enpro’s FAM subsea architecture which helped take one operator to first oil in 12 months, and a new game-changing seismic acquisition method being rolled out by BP. Back on land, Total speaks exclusively with InnovOil about the results of its ARGOS project, which has produced the world’s first autonomous inspection robot for oil and gas. After a three-year contest, the winners will now work with the super-major on a real-world pilot for the first-of-its-kind innovation. We also go behind the scenes at Statoil Technology Invest, the NOC’s venture capital unit, to find out how it chooses investment targets and what technologies hold the most promise. All this, as well as hydrate-busting pipeline coatings, autonomous electric ships, marginal field development and more. We are pleased to present the June issue of InnovOil.
Andrew Dykes Editor
NEWSBASE
InnovOil
page 6
June 2017
DSME loses LNG patent lawsuit Patent on partial reliquefaction technology ruled invalid as shipmaker loses case to rivals
Left: DSME’s latest carrier design incorporates the partial reliquefaction technology
S
OUTH Korea’s Daewoo Shipbuilding & Marine Engineering (DSME) has lost a lawsuit in which the troubled shipyard claimed its reliquefaction technology was proprietary and patentable. The South Korean Supreme Court ruled in favour of the company’s rivals Hyundai Heavy Industries (HHI) and Samsung Heavy Industries (SHI), which argued that the partial reliquefaction technology used by DSME was not that different from the process they had used. The court upheld their argument that DSME’s patent was invalid, meaning the shipyard will be banned from marketing the technology as its own when selling LNGfuelled vessels. DSME has, however, already benefited from its move in January 2014 to register the technology as patentable. The technology – which allows boil-off gas to be reliquefied for reuse as fuel on LNG carriers – has helped the company win LNG carrier orders. But the Supreme Court’s decision – which it made without even a hearing – cannot have come as a big surprise. The Patent Court of Korea had also ruled in January in favour of HHI and SHI on the issue. Before that, HHI and SHI had initiated patent invalidation battles against DSME with the Intellectual Property Trial and Appeal Board in December 2014 and March 2015.
Orders for environmentally friendly LNG carriers that use a mix of diesel and vaporised boil-off gas or natural gas as fuel have been increasing as environmental regulations covering the operation of ships tighten. The news comes at a difficult time for DSME, which remains plagued by heavy debt and continues to be propped up by its key creditors. Cash flow crisis The company appears poised to run out of cash again, so is due to receive 500 billion won (US$445.9 million) in fresh loans later this month that will cover payments to subcontractors and to employees. The new loans are part of a second bailout fund for DSME that was drawn up by its creditors, led by Korea Development Bank (KDB). The bank and other creditors announced in March a fresh rescue package for the shipbuilder, under which it will receive new loans worth 2.9 trillion won (US$2.59 billion), with bondholders and lenders swapping 2.9 trillion won of debt for new DSME shares. Bondholders have also granted DSME a three-year grace period for the repayment of remaining debt. Shareholders have also approved a proposal to increase the ceiling of sales of NEWSBASE
convertible bonds to 4 trillion won (US$3.57 billion) from 2 trillion won (US$1.78 billion) currently. This has paved the way for the shipyard to secure fresh funding from its shareholders. DSME’s debt ratio is anticipated to plunge to around 300% with the debt-for-equity swap, down from 2,732% at the end of 2016. KDB has announced separately on May 22 that its plans for a DSME bailout will not be scuppered by the objections of one remaining bondholder. The unidentified retail investor, which holds around US$1.4 million in DSME paper, sued last month to block the government’s restructuring plan for the shipyard. “As the top court is likely to reject the bondholder’s case, as did the lower court, the DSME restructuring is set to go forward,” a DSME spokesperson told Korea Times. For its part, DSME has pledged to put in place self-rescue measures worth 5.3 trillion won (US$4.73 billion) by the end of 2018. The company has already raised or saved 1.8 trillion won (US$1.61 billion) by selling off non-core assets and axing its work force but will struggle to find more fat to trim. Nevertheless, DSME remains confident that its turnaround efforts are working and that its shares – which were halted from trading in July 2016 owing to its impaired capital base – may resume trading in October. n
June 2017
InnovOil
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Kongsberg, Yara plan autonomous electric ship
Norwegian firms plan battery-powered ship to manage regional deliveries
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ORWEGIAN fertiliser producer Yara and maritime engineering group Kongsberg will team up to realise an ambitious electric shipping project. Yara is to commission a new vessel – named Yara Birkeland after the company’s founder – which it expects to be the first fully electric and autonomous container ship. The ship will be used to move products from Yara’s Porsgrunn production plant to global shipping hubs in Brevik and Larvik. Under current plans, operations would start in the latter half of 2018. The companies say this will reduce emissions and improve road safety by removing up to 40,000 truck journeys per year from the road. Yara Birkeland will initially operate as a manned vessel, moving to remote operation in 2019, and is expected to be capable of performing fully autonomous operations from 2020. Electric cranes and carriers will also be used dockside to continue its zeroemission commitments. “Every day, more than 100 diesel truck journeys are needed to transport products from YARA’s Porsgrunn plant to ports in Brevik and Larvik, where we ship products to customers around the world. With this new autonomous battery-driven container vessel we move transport from road to sea and thereby reduce noise and dust emissions,” added Yara president and CEO Svein Tore Holsether in a statement. Meanwhile, Kongsberg Maritime is to develop and deliver the technologies used on Yara Birkeland, including the sensors and integration required for remote and autonomous operations, as well as the electric drive, battery and propulsion control systems (consisting of two Azimuth pods and two tunnel thrusters). Details of the vessel are scant at present, as the two companies are only just moving into the design phase. However, Yara finance
and logistics manager Bjørn Tore Orvik told InnovOil by phone that he expected the ship would run on a battery of around 3.5 to 4-MWh capacity. He added that the 70m long vessel would hold around 100-150 containers, making 1-2 shipments per day, five days week. The Porsgrunn-Brevik leg is around 13 km or less – an easy feat for battery power alone. However, the challenge will be managing the longer trip to Larvik, a distance of around 30 nautical miles (55 km). Orvik said that charging would take around 2 hours, and would be straightforward at the factory and port because the sites had enough spare grid capacity. While Yara’s initial investment will be high, he was also confident that the operating costs would be lower than those for the existing diesel trucks. Fjording ahead Kongsberg is already heavily involved in the development autonomous shipping in Norway and further afield. In November 2016 it signed a memorandum of understanding (MoU) with UK-based Automated Ships to build the Hrönn – an innovation described as “the world’s first unmanned and fully NEWSBASE
automated vessel for offshore operations.” Automated Ships will act as project manager and ship-owner, while design and construction will be carried out in Norway in collaboration with shipyard Fjellstrand and Kongsberg. 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. “By moving container transport from land to sea, Yara Birkeland is the start of a major contribution to fulfilling national and international environmental impact goals. The new concept is also a giant step forward towards increased seaborne transportation in general,” said the company president and CEO Geir Håøy. “Yara Birkeland will set the benchmark for the application of innovative maritime technology for more efficient and environmentally friendly shipping,” Håøy added. The two companies will be designing the vessel over the next few months before embarking on a closed competition for a shipyard to build it. If all goes to plan, Yara’s fertiliser business is set to get even greener. n
A special report on the state of the gas industry and what the future holds. Click here to download your free copy.
InnovOil
Deep impact June 2017
page 9
Baker Hughes has launched DEEPFRAC™, a first-of-its-kind deepwater fracturing service
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HIS year’s Offshore Technology Conference saw Baker Hughes unveil its latest innovation for the deepwater market. DEEPFRAC™ is a deepwater multistage fracturing service, which the company says can save hundreds of millions of dollars in offshore developments through efficiency gains in the completion phase. The company believes that it is the first and only firm to have deployed a ball-activated multistage fracturing sleeve system in an openhole deepwater application. Although stimulation systems can unlock barrels of extra value from deepwater reservoirs, the payback may be hindered by the month-long wait to case and cement the well, displace mud to brine, and run lower and upper completions. More stages may increase this interval, and even with the luxury of time, conventional offshore stimulation systems are often limited to only five frac zones or stages. All in all, these complex systems lack flexibility, and an uneven treatment can create long sections of dead space, missing out hundreds of metres of viable pay. DEEPFRAC is aimed at speeding up completion time dramatically, while increasing the amount of reservoir contact. Modular momentum The system uses flexible, ball-activated multi-position sleeves that can be installed in openhole wellbores containing drilling mud – technology which has previously been refined in the onshore unconventional market. Baker Hughes’ VP of completions, Jim Sessions, noted: “By adapting some of the technologies and techniques that delivered game-changing efficiencies in unconventional land to an offshore service, we’ve enabled a new level of deepwater completion design flexibility and streamlined operations.” Without the requirement for casing and
cementing operations the system can be installed much faster than a conventional stimulation package. Modular assembly also allows for rapid stimulation of 20 or more tightly spaced stages – rather than the five expected from a typical system – which helps deliver more uniform stimulation. According to the company, these stages can be placed as close as 3.9m apart, helping to target areas of maximum pay. The DEEPFRAC sleeves have three positions: closed for run-in, frac ports open for treatment delivery, and frac ports closed with production ports open for flowback. No tool movement is required during the process. Instead, Baker Hughes’ IN-Tallic™ frac balls are used to shift the sleeve and then disintegrate downhole, enabling interventionfree production. The ball activation enables continuous pumping throughout the stages, cutting the lower completion phase from weeks to days. Another of the company’s technologies – BeadScreen™ proppant flowback control – is built directly into the DEEPFRAC sleeve’s NEWSBASE
production ports. The company says this offers greater reliability than conventional sand screens, and in some operations eliminated the surface flow tests that would have been required if these screens had been used. In that job, this saved an estimated two and a half days in completion time. In practice, Baker Hughes says the system can deliver average OPEX savings of US$30-40 million per well – not counting the additional oil produced from the targeted stimulation sites. On a recent 15-stage deepwater completion in the Gulf of Mexico’s Lower Tertiary, the DEEPFRAC service saved the operator an estimated 25 days rig time and US$40 million compared with a conventional cased-hole multizone option. If such savings can be replicated across additional wells, it should be little wonder that the deepwater market is heating up. n Contact: Melanie Kania
Tel: +1 (0)713 439 8303 Email: melanie.kania@bakerhughes.com Web: www.bakerhughes.com
InnovOil
page 10
On the radar
What caught our attention outside the world of oil and gas this month
Spongey Batteries Researchers from the Navy Research Laboratory’s (NRL) Advanced Electrochemical Materials group are leading an effort to create an entire family of safer, water-based, zinc batteries. The team has demonstrated a breakthrough for nickel-zinc (Ni-Zn) batteries in which a 3D Zn “sponge” replaces the powdered zinc anode traditionally used. Using Zn in this configuration, the battery provides an energy content and cycle to rival lithium-ion batteries, while avoiding the safety issues that continue to plague lithium. Zinc-based batteries are the go-to global battery for single-use applications, but are not considered rechargeable in practice largely because of their tendency to form conductive dendrites inside the battery, which can grow long enough to cause short circuits. “The key to realising rechargeable zinc-
based batteries lies in controlling the behaviour of the zinc during cycling,” said Joseph Parker, lead author on the paper. “Electric currents are more uniformly distributed within the sponge, making it physically difficult to form dendrites.” The NRL team demonstrated Ni-3D Zn performance in three ways: extending lifetime in single-use cells to above 90% of its theoretical depth of discharge (DODZn); cycling cells more than 100 times to 40% power, at an energy content competitive with lithium-ion batteries; and cycling cells more than 50,000 times in short duty-cycles with intermittent power bursts, similar to how batteries are used in some hybrid vehicles. Having demonstrated its ability to be successfully recharged, the 3D Zn sponge architecture can be deployed throughout the entire family of Zn-based alkaline batteries across the civilian and military sectors.. n
June 2017
Denser sensors The application of better fibre-optic technologies could enable engineers to monitor millions of infrastructural stress points faster than before, offering advanced warnings if any structural changes occur. The new technology was developed by a team at the University of Alcala (UAH) in Spain and the Swiss Federal Institute of Technology (EPFL). Using a 10-km distributed sensing optical fibre, the team can sense strain and temperature changes from 1 million sensing points in less than 20 minutes. The new sensor is about 4.5 times faster than previously reported sensors with the same number of sensing points. More discrete points mean fewer fibre-optic units are needed to monitor an entire structure. Traditional methods of generating the continuous signal could cause distortions in the system at higher laser powers, but by changing the way that laser signal was generated, the team increased laser power and improved sensing performance. The technology could be of use in other sectors. “Because we have such a large density of sensing points – one per centimetre – our optimised sensor could also be used for monitoring in applications such as avionics and aerospace, where it’s important to know what is happening in every inch of a plane wing” said UAH’s Alejandro Dominguez-Lopez. Using the new approach, the researchers demonstrated that they could measure the temperature of a hot spot to within 3°C, from the end of a 10-km fibre. Their next steps will be to decrease acquisition time and gather results faster. They will also work to increase the density of sensing points which may allow the technology to expand into new areas, such as the biomedical sector. n
Nano holograms A team at RMIT University has designed a nano-hologram which could be integrated into the displays found in phones and computers. The images are simple to make, can be seen without 3D goggles and are 1,000 times thinner than a human hair. Their research was published in Nature Communications on May 18. “Conventional computergenerated holograms are too big for electronic devices but our ultra-thin hologram overcomes those size barriers,” distinguished Professor Min Gu said. “Our
nano-hologram is fabricated using a simple and fast direct laser writing system, which makes our design suitable for large-scale uses and mass manufacture. “Integrating holography into everyday electronics would make screen size irrelevant – a pop-up 3D hologram can display a wealth of data that doesn’t neatly fit on a phone or watch.” Conventional holograms modulate the phase of light to give the illusion of 3D depth. But to generate enough phase shifts, those holograms need to be the
thickness of optical wavelengths. The RMIT team, working with the Beijing Institute of Technology (BIT), successfully broke this thickness limit with a 25-nanometre hologram based on a topological insulator material – a novel quantum material that holds the low refractive index in the surface layer but the ultrahigh refractive index in the bulk. The thin film acts as an intrinsic optical resonant cavity, which can enhance the phase shifts for holographic imaging. The next stage for the research
NEWSBASE
will be to develop a rigid thin film that could be laid onto an LCD screen to enable 3D holographic display. To achieve that, the team’s pixel size will need to be shrunk by at least ten times. n
InnovOil
June 2017
page 11
Four-legged friend InnovOil has featured the advancements in 3D-printed robotics before, but a team at the University of California San Diego has put these new techniques into practice. Engineers have devised the first soft robot capable of walking on rough surfaces, such as sand and pebbles. New 3D printing techniques allow rigid and flexible plastics to be printed alongside each other, enabling hydraulic and pneumatic systems to be built in record time and at a tiny scale. The four-legged robot features legs consisting of three parallel, connected sealed inflatable chambers, or actuators, 3D-printed from a rubber-like material. The chambers are hollow on the inside and bellowed outside, allowing engineers to control their movements. The flexibility of this system enables the legs to walk, rather than shuffle or crawl as previous systems might. The robot’s gait depends on the order of the timing, the amount of pressure and the order in which the pistons in its four legs are inflated. The current prototype is tethered to an open source circuit board and an air pump. The team is now working on miniaturising both the board and the pump so that the robot can walk independently. The challenge here is
to find the right design for the board and the right components, such as power sources and batteries, according to mechanical engineering professor Michael Tolley.
The team will be presenting the robot at the IEEE International Conference on Robotics and Automation from May 29 to June 3 in Singapore. n
Ethylene to graphene in 3 easy steps Experiments conducted at the Georgia Institute of Technology have successfully produced graphene by heating ethylene over a series of stages. By heating the ethylene gas to a temperature just above 700°Celsius the researchers deposited pure layers of graphene on a rhodium catalyst substrate. This was done at a lower cost and greater simplicity than previous techniques – which typically involve vapour deposition or careful exfoliation from graphite – potentially opening new applications for the material. The study was conducted by scientists at the Georgia Institute of Technology, Technische Universität München in Germany and the University of St. Andrews in Scotland, and in the US was supported by the US Air Force and the US Department of Energy (DoE). Researchers reasoned that the path from ethene to graphene would involve the formation of a series of structures as hydrogen atoms leave the ethene molecules. The sequence starts from adsorbed ethene at 300K
(27°C), leading to self-evolved 24-carbon atom cluster precursors between 570K and 670 K (297-397°C), and culminates with graphene formed at elevated temperatures between 770K and 970K (497-697°C). “All along the way, there is a loss of hydrogen from the clusters,” explained Uzi Landman, a Regents’ Professor and F NEWSBASE
E Callaway endowed chair in the Georgia Tech School of Physics. “Bringing up the temperature essentially ‘boils’ the hydrogen out of the evolving metal-supported carbon structure, culminating in graphene.” The resulting graphene is adsorbed onto a rhodium catalyst, but future work will seek to identify ways to remove it. n
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PROJECT INNOVATION June 2017
page 13
SPECIAL SUPPLEMENT Pages 13-20
ENPRO TIPS
How the ESSI FAM system unlocked one subsea development
IN SEARCH OF ATLANTIS
BP’s seismic revolution
Page 16
Page 18
STAYING AFLOAT
Installing Trelleborg DBMs on a live riser Page 14
NEWSBASE
page 14
InnovOil
June 2017
PROJECT INNOVATION
Trelleborg and SubC help early risers
Trelleborg explains how a new, world-first approach enabled the replacement of riser buoyancy modules without any loss of production
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N floating production operations, pipelines such as flexible risers, cables and umbilicals are often required to be held subsea in specific geometric configurations to prevent over-utilisation of the system. Typically, this is achieved by attaching buoyancy modules to the outside of the pipeline, which provide uplift and maintain its location. These distributed buoyancy modules (DBMs) are comprised of a clamp and a buoyant jacket. The module is fitted to the desired location and locked with a fastening system, usually while the structure is topside, prior to the installation of the riser itself. Previously it has not been possible to attach the buoyancy on a live riser; the riser would have to be disconnected to perform the operation, halting production and incurring significant costs as a result of the downtime. However, in a collaborative project completed last year, Trelleborg and SubC Engineering designed, manufactured and fitted a new form of DBM suitable for installation by an ROV. This was successfully fitted to a 12-inch (305-mm) production riser on a floating production storage and offload (FPSO) vessel in the UK Continental Shelf. Installation by ROV meant that the modules could be replaced on a live riser, in a steep wave configuration, without shutting oil production – a world-first achievement. According to operator Maersk Oil, this also represented an 80% cost saving compared with riser replacement, as well as additional savings thanks to avoided loss of production. Trelleborg Offshore key account manager, Andy Hey, took InnovOil behind the scenes of the project. C here As with a great many innovations, this project was less about a paradigm shift in subsea equipment, and more about the confidence and design capability to use existing equipment in a smarter way. “It was
Xxxxx
essentially a combination of clever design and the biggest ROV on the market,” Hey explained. Maersk had previously considered this type of replacement, but decided against it based on the unknown parameters of doing so. Although several firms had tendered for the job of DBM provision, Hey believes that few had comparable engineering expertise, and he credits much of the success on the project to Trelleborg’s “very capable” design team. The approach to the project had two prongs: Trelleborg would design and build a new type of DBM, while SubC engineered a bespoke suite of hydraulic ROV tools capable of removing the old modules and deploying new ones. This required a lot of investigation and testing from both parties. In the first phase, these tools had to be capable of positioning onto the existing DBMs, adjusting their ballast, cutting holding straps and then delivering the element to a crane for retrieval to the surface – with a similar process for the riser clamp. This would then be conducted in reverse to fit, secure and ballast a new clamp and module (see video). It presented a number of difficult parameters. In addition to the design of the hydraulic tools for mounting, there were also issues of ballasting, and the amount of power NEWSBASE
to lift needed. Hey said it was difficult to find an ROV which was capable of meeting these requirements, and one which could then fit the modules with the accuracy required. From Trelleborg’s side, its internal clampto riser interface was based on a hinged version of its existing “Type 2” friction clamp, with nylon segments and rubber pads for added security. This was particularly suitable because the clamp had no loose components, but the tightening mechanism was redesigned to work with the ROV interface. During testing, clamp performance was good, achieving a slip load in excess of 33 kN at ‘end of life’ conditions. In prototype testing the design’s hinged crossbars also allowed for fastener tightening despite a variance in the tightening sequence when performed by ROV. Trelleborg Customer Group Manager Andy Smith added that: “A variety of installation features and precise datum points had to be built in to the buoyancy modules to provide a known and repeatable interface between ROV installation tooling and the DBM components. Dimensional tolerances on a buoyancy element shell are generally intrinsic to the roto-molding manufacturing process.” The buoyancy element fasteners – the mechanism that holds the two buoyancy
June 2017
InnovOil
page 15
PROJECT INNOVATION Left: Cross-section of the buoyancy module and clamp Right: DBMs are typically used between a subsea structure and a surface vessel or platform
halves together – also had to be captive. As a result, Trelleborg used a bolted flange tightening system instead of circumferential securing straps and tensioners. However, this presented increased the risk of module misalignment when the elements were paired. In response, engineered designed bespoke ‘floating’ nuts and bolts, which self-align upon engagement, meaning that every element would be aligned correctly and secured. Given the nature of the project, both parties hard to provide a “definitive amount of information” to Maersk to prove calculations and to understand how the ROV would perform. However, with the company’s backing the project was cleared to proceed. Done in minutes A joint team worked aboard an offshore service vessel for around three weeks, removing or adding one module per day. “Our goal was to install 10 and we did 9,” Hey said, although this unsuccessful fitting was based on incorrect specifications given by the operator – a problem which was easily rectified.
In practical terms however, the changeover of individual modules was exceptionally fast. During the operation the team successfully averaged around 8-9 minutes per module, he explained. Using a moon pool, that time has been reduced even further, and modules can now be fitted in around 4-5 minutes per unit. With all modules installed and secured as expected the team continued to monitor the riser performance to ensure its safety. “As it moves, the umbilical fluctuates in pressures, and doesn’t remain in a static position. Once the full assembly was in place we monitored it via ROV and other equipment,” he explained. So far however, results have been extremely good, with the riser remaining in place as expected for well over a year now. Having been plagued by bad performance from a poorly configured riser for months, Maersk was – in Hey’s words – “elated” by the results. Being a first-of-its-kind project, and given the size of ROV required, Hey acknowledged that the overall cost of design and installation was high. But with the system proven, and NEWSBASE
the partners comfortable with the system, future installations should be possible in a matter of days, if not hours. In the case of this project, in addition to the “millions” in savings Maersk identified compared with riser replacement, the savings achieved through continued production offset higher DBM installations by 3 or 4 times. With the system was conceived as part of a partnership between the two companies, Hey confirmed that the two will be pursuing future work with the system, marketing it both individually and collectively. Trelleborg itself has had several productive discussions, and a number of operators are now interested in retrofit projects, where the original riser clamp would be maintained and the buoyancy module replaced. With most risers requiring around 10-15 modules each, Hey said there is a strong argument for more operators to consider the method. n Contact: Andy Hey
Tel: +44 (0) 7876885290 Email: andy.hey@trelleborg.com Web: www.trelleborg.com/en
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InnovOil
ESSI does it
June 2017
PROJECT INNOVATION
Enpro Subsea discusses its ESSI FAM system, and how it has helped one operator to reach first oil in just 12 months
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N an age of constant cost pressures, equipment suppliers and service firms are being asked to push the envelope continually. In the subsea sector, increasing standardisation and a focus on more plugand-play solutions have been key drivers to achieving this but the pressure is still on to work more efficiently and effectively. One firm leading the way in this open approach is production optimisation specialist Enpro Subsea. The company’s proprietary Enhanced Subsea Sampling & Injection (ESSI) and Flow Access Module (FAM) systems offer support for a wide range of production issues throughout field life, from first oil to decommissioning. FAM is a universal production optimisation interface, consisting of a range of interchangeable modules which can be attached to the FAM Hub – “basically a subsea USB port,” Enpro managing director Ian Donald explained to InnovOil. The hub itself is a dual-port structure which is supplied either with new hardware, or permanently retrofitted onto existing infrastructure, and located at the PLEM, PLET or at the flowline termination either at the tree or manifold. “Our technology provides an enhanced subsea architecture which enables you to address some of the 10-20% gap in recoverable oil we observed between the use of platform wells and subsea wells. The FAM allows you to intervene on the wells more flexibly and in a simpler way,” Donald added. Because the FAM is located outside the subsea tree, it is independent of other hardware decisions, allowing project teams to fast-track procurement. Modules can be used independently, in series or in combination to support various production optimisation plans, including stimulation, sampling, multiphase metering, pumping, flow assurance operations and more. Working with standardised architecture, Enpro says, enables it to deliver faster, more cost-effective and more flexible subsea systems. Recently, the equipment was used for the first time by an operator in the Gulf of Mexico, enabling the organisation to achieve first oil
production in under 12 months – a record time for the client. Working in parallel The challenge in this case was to tie back a new production well via a single spur into an existing subsea flowloop in the Mississippi Canyon, via a 3.2-km line. Donald recalled that conversations first began during a subsea tieback conference in San Antonio and that discussions progressed, with Enpro Subsea eventually invited to assist in the design of a solution which could make use of the operator’s existing deepwater infrastructure at the asset, and a surplus inventory of standardised subsea hardware. For the project to remain competitive, the operator also set a deadline of 12 months, from concept to first oil. Enpro business development manager for the Gulf of Mexico Adam Hudson explained: “The traditional method for installing subsea hardware, up until the latest downturn, appeared to be that the more complex you could make your equipment [and] the longer the lead time, everybody believed the more successful and safer your project would be. The latest oil price reduction has provided challenges to the market to innovate and to reduce cost while making the systems more reliable, and as safe or safer. Enpro’s technology meets this innovation challenge and exceeds the requirements with added flexibility and functionality, while reducing costs.” In a bid to reduce cost and drive efficiency, the operator’s project team had moved from a dual flowline design down to a single flowline, and had evaluated different technologies for using goosenecks in a flexible flowline. “The technology present at the time did not give them that flexible design,” he said. “Enpro technology allows for that flexibility; for a small additional cost you’re able to save much larger amounts from the overall project cost. And it allows for the acceleration of the project.” For the operator, Enpro’s offering “ticked a lot of boxes.” It allowed electronic components and valves to be retrievable, and enabled a NEWSBASE
comparable engineering solution in a smaller form. This made for easier installation by a flexible flowline installation vessel. Overall, Enpro provided several key pieces of equipment to the project, including flexible goosenecks with integrated FAM hubs and isolation valves onto two different OEM jumper connectors; metering FAM that included a multiphase flowmeter, standalone water cut meter and acoustic sand detector; a Flow Assurance FAM that included a hydraulically actuated fail close valve, pressure sensors, temperature sensors, chemical injection valves and an Intervention FAM. The modular design also enabled the team do parallel engineering. A subsea tree could be installed and completed more than four months before the additional electronic components were in place. In this case the component was another piece of new technology, a standalone water cut meter, which allowed the operator to monitor the water cut in the produced fluids. The ability to deploy this via FAM enabled the operator to accelerate the entire project by three to six months. “In a traditional project the operator would have waited until April to install that component into a tree and then would
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PROJECT INNOVATION Subsea tree with FAM gooseneck and metering module
have proceeded with the installation and completion of the tree, backing the project up and losing six to nine months,” Hudson added. “By doing the project this way they didn’t wait on this technology. That sensor was installed into a retrievable FAM module with a much later delivery time requirement. The beautiful thing about the Enpro technology is that it’s jumper-based, and subsea well jumpers are typically the last component installed in subsea infrastructure and build out,” he explained. “That gives you more time to have long-lead electronic components delivered.” Collaborative effort The use of the ESSI FAM system also helped address a number of unique challenges posed by the project location and specification. Because the design had eliminated a flowline and opted for a flow spur, heated dry oil could not be circulated if the well was shut in during emergency or maintenance. Instead, engineers opted for an isolation valve which could be remotely controlled from the facility, but were faced with the problem of where to mount it. Having evaluated using additional standalone structures to hold the valve, or
mounting the valve into the gooseneck, they approached Enpro to help configure a module in which it could be included. Working collaboratively the two teams devised a system which met the requirements, and could also be deployed as part of a FAM module. “Doing so also gave them opportunity to inject chemicals into the module on both sides of the valve to further assist with safety and flow assurance activities,” Hudson noted. Owing to the configuration of the field and the fact that production flowed downhill, there were also several contact points where gas and water could collect together at high pressures, risking hydrate formation. Hudson added that Enpro’s FAM solution allowed for one module to be retrieved and an intervention module installed in its place, enabling much simpler hydrate remediation, were that to occur. Because Enpro’s technology is designed to interface with equipment from all manufacturers, including different hub connectors, the operator could use existing stock hardware, offering further cost savings. The future of FAM Having successfully delivered the project within a challenging timeframe, and having NEWSBASE
provided additional functionality, Enpro is now pursuing work for longer tiebacks to the same installation. Interest in the technology is also beginning to grow. “We’re seeing opportunities that would lead us to 8-well, up to 30-well developments, where this enables a very flexible strategy to be adopted,” Donald noted. In addition to new greenfield projects, the open architecture also makes ESSI and FAM cost-effective for retrofits. “One operator is fitting it to existing wells and is now planning to use the system for their new wells, as a useful life of field,” he continued. The architecture can also offset risk. Donald drew attention to the fact that by offsetting some critical components from the tree, operators could work more flexibly: “If you put the same functionality in a tree it will cost you more, and if you damage anything on the tree you will have to come in with the ability to shut off the well and incur a bill of tens of millions.” Damaging a jumper, meanwhile, might be in the range of US$2-3 million – “There’s an order of magnitude difference in the downside costs as well,” he added. “In terms of risk and functionality we think the benefits are quite significant.” With greater interest comes new innovation. The company has identified a range of production optimisation tools that can be deployed through this type of system and is now focusing its efforts on developing the broader architecture to support them. “We’re developing a 15ksi version of the ESSI which we expect will be available for deployment for next season,” Donald said. “We see certain applications for hydraulic intervention, metering, sampling and pumping coming very much to the fore.” With no shortage of subsea wells on the horizon, the future of subsea engineering looks like it might get a little ESSI-er. n Contact: Ian Donald / Adam Hudson
Tel: +44 (0)1224 974 000 / +1 713 502 0363 Email: idonald@enpro-subsea.com / ahudson@enpro-subsea.com Web: www.enpro-subsea.com
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PROJECT INNOVATION
BP drives seismic changes in the Gulf of Mexico
Ros Davidson reports on the seismic breakthrough at BP making waves throughout the Gulf of Mexico
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EOPHYSICISTS at BP’s Subsurface Technical Centre in Houston have achieved what they say is a “major breakthrough” in advanced seismic imaging. The two-part novel technique has already allowed scientists to identify additional oil resources underneath salt formations better than ever before. At the recent Offshore Technology Conference (OTC) in Houston, BP’s regional president Richard Morrison said that the new sharper images would allow the UKheadquartered company to identify as much as 1 billion additional barrels of new “possible resources” beneath the belt of salt domes which underlie the Gulf. Morrison said the technique would be applied to four of the supermajor’s deepwater fields: Atlantis, Mad Dog, Thunder Horse and Na Kika. A few days earlier, BP formally announced that the breakthrough had led to the discovery of an extra 200 million barrels of additional resources in the eastern area of Atlantis, a field originally discovered in 1998. The BP-operated field lies in the Green Canyon area, at a water depth of more than 2,100m, and is the company’s deepest moored floating platform in the Gulf. Wood Mackenzie had previously estimated Atlantis’ recoverable reserves as 744 million barrels, suggesting that better seismic imaging may have a profound effect on the company’s reserves, and its production. New resources discovered at Atlantis alone could be worth about US$2 billion, according to unofficial estimates. Pillars of salt The breakthrough involves acquiring more data and then using a new and proprietary algorithm to process it much faster than before. “This degree of success has not been accomplished before in the industry, imaging a field below a complex salt formation with an automatically derived subsurface
model,” John Etgen, BP’s distinguished advisor for seismic imaging, told InnovOil. The enhanced imaging is also applicable in other situations where the seismic image of a reservoir is obscured, for example by volcanic formations, or in shallow gas-bearing fields. Although seismic imaging remains one of the industry’s most standard tools, formations such as salt domes routinely complicate the imaging process by distorting or obstructing the acoustical waves. A salt dome acts as an acoustic lens, refracting and scattering the sound waves, but the presence of such domes is often associated with hydrocarbon reserves – leaving seismologists and drillers with a challenge to pinpoint these resources accurately. BP’s breakthrough has two components: First, the way in which BP’s geophysicists collected data was improved. They expanded the amount of information collected by approximately doubling the length of the ‘offsets’ – the distance between the location of the receivers on the ocean floor and the seismic source vessel – used during the imaging process. Typically, the length of offsets that had been used in Atlantis was 8-10 km, but that was upped to 25 km, said Etgen. Longer offsets have also now been used at Thunder Horse, which is estimated to contain about 1 billion barrels in recoverable resources. Longer offsets had not previously been used so successfully. Before the advent of full waveform inversion (FWI), there was no clear consensus that longer offsets would be sufficiently valuable, given that they raise the cost of seismic acquisition, he explained. “So, in a way, it was just a historical thing that we didn’t know how to get effective use from them, so why bother to pay for them. Now that we know how to use them, they seem to be very important and beneficial,” he said. FWI builds a model of subsurface properties, such as the speed at which sound NEWSBASE
BP’s Atlantis platform
waves propagate, and can thus predict what is underneath an obstruction, such as a salt dome, and produce high-quality subsurface images. FWI and the synthesised data it produces – which is matched to data recorded in the field – have been used widely in oil exploration for more than 10 years. BP had previously invented and was the first company to deploy wide-azimuth towedstreamer (WATS) technology to illuminate better and image below complex structures like salt by capturing data from wider angles; however, it seems that the new method may provide even greater detail. Altered images To turn the collected data into more accurate images, BP scientists then used a new algorithm developed at the company’s Subsurface Technical Centre. The algorithm was applied to seismic data run at BP’s Centre for High Performance Computing in Houston, one of the largest supercomputers in the world dedicated to commercial research. The supercomputer has a processing power of 6 petaflops – almost 6,000 trillion calculations per second – and takes up about 14,000 square feet (1,300 sq metres) at the Centre, which was opened in 2013. The new automated algorithm, in conjunction with other processing algorithms that the supermajor had employed previously
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PROJECT INNOVATION
– enhanced the FWI process and allowed data that would normally take a year of analysis to be processed in just a few weeks. BP says it was thus able to accelerate its development recommendations for Atlantis considerably. Etgen could not comment on what exactly makes BP’s new algorithm better – it remains a proprietary technology – but did add that it was developed by a scientist just two years out of graduate school at Stanford University, 32-year-old Xukai Shen. The technology was first used at Atlantis a little more than a year ago, with the first “intriguing” results delivered in early 2016, he added. Feedback from other members of BP’s leadership has been similarly glowing; in a statement the company’s upstream technology director Ahmed Hashmi commented: “The new technique has produced the best images of this reservoir that we have ever seen.” The quest for improved understanding of reservoirs is never-ending. Once a field is discovered, geophysicists are always trying to improve their imaging so that drilling can be done with confidence. Etgen concedes that the initial seismic image of Atlantis was poor, largely because of the salt dome, and that the reservoir’s architecture could not be understood properly. Consequently, drilling was always liable to be inaccurate in parts of the field.
The new seismic technique offers much greater detail of the reservoir “Really, this latest breakthrough is about the efficiency of how we do our business,” explained Etgen. ”We often know the upper boundary [of a field’s size], and the real goal is to improve the recovery factor,” so much so that the technique is to be applied to other areas of operation. BP global upstream chief executive, Bernard Looney, recently noted: “This technological breakthrough has essentially allowed our team to find a new oilfield within our existing Atlantis field. Given the overwhelming success of this project, we are now deploying this technology across BP’s global operations.” Oil and gas fields are not always suitable NEWSBASE
for this kind of imaging, for example if there is insufficient field data, but evidently the operator sees the potential for seismic improvements around the world. The technology is now being lined up for fields elsewhere in the Gulf of Mexico. First up is Mad Dog, which has an estimated 5 billion barrels of oil in place (OIP). It will then be used for fields in Azerbaijan, Angola, and Trinidad and Tobago, where salt domes have also obscured images in the past. In addition, BP has leases for fields that contain shallow gas-bearing formations in the Caspian Sea and off Trinidad, which are also prime prospects for the new technology. n
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Injunction halts Statoil’s Cap-X deployment NeoDrill raises concerns over patent infringement of suction anchor systems
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TATOIL has hit a legal snag that could affect its recently launched exploration campaign in the Barents Sea. Norwegian offshore contractor NeoDrill has been granted a temporary injunction preventing the state-run E&P giant from using its new Cap-X technology. The Cap-X seabed foundation system comprises a steel suction anchor with a fibreglass housing fixed on top. This square-based pyramidal superstructure forms a protective casing capable of housing standard subsea equipment. Designed to bring “plug-in-and-play” standardisation to the industry, Statoil said it reduced the subsea footprint by around 75%, and was around 30% cheaper to produce and install than comparable existing solutions. But when the technology was unveiled last year, subsea specialist NeoDrill (which itself is part-owned by Statoil) accused Statoil of using its own suction anchor technology in breach of patents. Statoil eventually conceded it may have infringed patent rights, and the two companies commenced talks to resolve the dispute. Statoil wants to deploy the technology as part of its push to open up the Barents Sea, and it was also scheduled for use in the Bauge development in the Norwegian Sea. In April, it began drilling the first of five planned wells at the Blaamann prospect in the Barents Sea, and five Cap-X suction anchor systems were installed on the seabed to serve as well foundations, despite the fact that the discussions with NeoDrill were still ongoing. According to Norwegian business journal Dagens Naeringsliv (DN), NeoDrill decided to apply to the Stavanger District Court for an injunction to stop the work, claiming Statoil had gained access to patent-protected technical information as part of a wider partnership. The court agreed, and ordered Statoil to stop using Cap-X until ownership
Above: Statoil model of CapX technology. Picture: Statoil/Kjell Einar Ellingsen Left: Neodrill CANductor design
of the technology rights can be established. When the court’s ruling came on May 24, Statoil initially sought to have it overturned, claiming it was based on “incorrect information.” However, the company has now agreed to the temporary order, and said it would actively look for short-term alternatives to allow it to continue working. NEWSBASE
“We are pleased the court has fully endorsed us, and hope Statoil will respect our patent rights and act as we expect any partner to do. I also hope this will make it possible to establish a sensible and balanced dialogue with Statoil in the interests of both parties,” NeoDrill’s general manager, Jostein Aleksandersen, told DN. n
Total Robot InnovOil
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June 2017
Team Name: AIR-K Robot: Autonomous gas-leak Inspection Robot type K Country of Origin: Japan Members: BestTechnology, Mobile Robot Research, FUJISOFT, Tohoku University, Shibaura Institute of Technology
Team Name: LIO Robot: Legged robotic Inspection for Oil & Gas Industry Xxxxx Country of Origin: Switzerland Members: ETH Zurich, Alstom Inspection Robotics
Andrew Dykes reports on the winners of Total’s ARGOS Challenge, which sought to find and develop the first surfacebased autonomous inspection robot for oil and gas sites
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UBSEA work is ruled by fleets of ROVs and AUVs. Advances in robotics and communications have propelled these machines to their current status as the indispensable workhorses of the offshore and marine energy industry. In doing so, operations which might have previously taken weeks of dangerous work by diving teams can be accomplished in hours by a few well-tooled robots. Why, then, had we not done the same for surface work? Even as the industry moves towards the long promised digital oilfield, installations tend to be maintained and inspected by personnel, even in cases of extreme isolation or environmental conditions. But with the right tools, remote and autonomous robots could monitor and maintain these installations, lowering the amount of human intervention required, improving safety and saving considerable operating costs. The initial problem, in the eyes of supermajor Total, was that this technology did not yet exist. Speaking by phone, Total E&P prospective and R&D strategy senior manager Sylvie Duflot told InnovOil: “At the time there were no other autonomous robots for oil and gas, so it wasn’t possible to [invest in one directly]. It was our intention to really NEWSBASE
be the ones to create the first autonomous surface robot for oil and gas sites.” It was with this goal in mind that Total launched the ARGOS (Autonomous Robot for Gas and Oil Sites) Challenge in December 2013, in partnership with the French National Research Agency (ANR). Putting out an open call to international universities, OEMs and labs, ARGOS sought designs for the first autonomous surface robots adapted specifically for oil and gas sites, and compliant with ATEX/IECEx (explosive atmosphere) standards. Teams of engineers would then pit their robots against each other in series of scenarios and tests in pursuit of a 500,000 euro (US$560,000) prize. This would allow Total and its judges, assembled with the help of ANR, to survey the state-of-the-art equipment in terms of robotic capabilities. Time was also of the essence if the company was to be serious about deploying these vehicles to real assets, Duflot said. “We thought an open innovation challenge was the best way to get the best team and to speed up the R&D process.” A total of 31 consortia submitted applications, with five teams selected to compete. Each was given up to 600,000 euros (US$670,000) in funding from
Wars June 2017
InnovOil
Team Name: VIKINGS Robot: Robotic Vehicle using Intuitive Kinematics and Innovative Natural Guidance Systems Country of Origin: France Members: IRSEEM, SOMINEX
Team Name: FOXIRIS Robot: Flipper-based Oil & Gas ATEX Intelligent RobotIcs System Country of Origin: Spain & Portugal Members: GMV, IdMind, UPM-CAR
Total, and following a launch meeting in September 2014, each group then prepared for the first round of trials the following summer. After a long, trying road and three difficult rounds of tests, the winners were finally announced in May 2017. Intelligent design For Total and the ARGOS judges, it was important that these tests were not easy. If robots are to be deployed in these environments, they must be capable of dealing with a wide variety of conditions and tasks without physical intervention. In addition, unlike subsea ROVs these robots do not have the benefit of a tether system for communications and power. In its challenge brief, Total noted the problems of avoiding obstacles; climbing stairs; taking equipment and environmental readings; working in poor weather conditions (e.g. wet or slippery floors) and detecting anomalies such as fluid or gas leaks. Moreover, each trial presented the teams with increasing levels of difficulty. Many of these might be mitigated by good design and skilled operation, but the robots also had to be capable of operating autonomously in a number of tough situations. ARGOS required them
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Team Name: ARGONAUTS Robot: Autonomous ATEX Certified Robots for Oil & Gas Industry Country of Origin: Austria & Germany Members: Taurob GmbH, TU Wien, TU Darmstadt
to perform some inspection unassisted, including carrying out “spot” reporting and inspecting hard-to-access or isolated areas. In addition to autonomy, the robots had to be intelligent. ARGOS Challenge project manager in R&D Kris Kydd noted: “The robot must be able not only to read and record values on instruments, but also to autonomously determine whether or not the values it reads are within a normal operating range.” The teams were then tested on how their innovations handled emergency scenarios – for example, being able to send an emergency signal to operators when an oil or gas leak occurred or when those readings were abnormal, and to transmit data and images of the situation in real-time. The site of the trials was a decommissioned gas installation in Lacq, southwest France. The UMAD (Availability Unit) was a former gas dehydration unit managed by SOBEGI and is now used for training human operators and emergency response teams. What better place to put the teams to the test? The final five The final teams selected to compete included Japan’s AIR-K, Spain and Portugal’s FOXIRIS, France’s VIKINGS, LIO from NEWSBASE
Switzerland and the Austro-German ARGONAUTS. While the competing designs had some common elements – four teams opted for tracked crawlers, and most for a pivoting sensor on top for imaging and detection – the robots were all fairly distinctive, and a far cry from the box-like homogeneity of subsea ROVs. Designing far outside the conventional box, LIO even opted for a legged quadruped with sensors it in its feet, truly a step away the crawlers that have dominated the robotics industry for decades. For the remaining four, stairs were to be navigated by movable flippers on which the tracks were mounted. All adopted various levels of environmental proofing, including for dust and other debris, as well as waterproofing, enabling them to operate in the remote and extreme environments expected of them. Sensors also had to be robust – the housing used in the ARGONAUTS equipment, for example, was fully compliant with IP67 regulations. Some also opted for greater freedom of movement in their inspections. By the end of the competition, FOXIRIS had upgraded its design to include a full robotic arm with cameras and detection equipment.
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Battle commences The first competition, held in June 2015, focused on navigation and inspection on the ground floor of the Lacq UMAD installation. However, even setting up this round this proved challenging, DuFlot said. “We needed a very robust communication system, and what we got in the first round was five different wireless systems for controlling robots. It was a difficult moment, I would say, but luckily we have some top telecommunications engineers in Total and we were able to hold the competition.” Was Total aware at the difficulty of the challenge it had set the teams? “To be honest, no!” Duflot said. “I believe it was the same for the teams. It was a really difficult challenge because we really wanted the robot to have these requirements – autonomy, ATEX certification, for it to be reliable – so we had big expectations and the bar was quite high.” Less than a year later, in April 2016, the second round of challenges upped the difficulty. Duflot was present during the event and “was quite amazed by the improvement of the robots from the first stage in the competition. They were working a lot to improve their robots and all made incredible progress.” The first day tested a robot’s ability to navigate a staircase autonomously, taking itself to the first floor of the structure and back unassisted. It also asked the robots to navigate an obstacle, assess its size and dimensions and then decide on whether that obstacle was passable, or alter its route. Most proved to be more than capable of independently tackling stairs – perhaps the mortal enemy of robots past – but over-sensitive instruments let down teams like LIO, whose robot detected obstacles correctly, but produced too many outliers. The second day of testing forced the vehicles to search the site for a heat source. Here ARGONAUTS failed in its first run around the UMAD structure, but the robot moved fast enough to allow them another sweep, which was successful. A subsequent test saw the judges move gauges and instruments around the site. Robots then had to search for each and report back any inconsistencies between the installation and the 3-D model the robot used for reference. The final day of tests threw everything at the teams, including water leaks, a loss of Wi-Fi communications, a simulated gas leak which they had to detect, and tested their ability to climb and descend stairs both autonomously and with manual control.
InnovOil
At the end of the three days, VIKINGS was in the lead. By the third round in March 2017, some of the robots were unrecognisable from their original forms. Refinements, additions and work on ATEX certification produced vehicles which already looked field-capable. The latter requirement formed one of the first assessments, with ATEX experts brought in to confirm the compliance for the vehicles to work in a potentially explosive atmosphere. Over the course of a week, robots were given new tasks, including navigating gravel, to detect mobile, traverse obstacles (barrels, flexible hoses and ditches) and to conduct acoustic monitoring autonomously using pump signature analysis. “During the last competition a member of the jury even stood in front of the robot without prior warning, testing its ability to stop and identify the obstacle before changing its route and mission plan,” Duflot added. Building on the tests in the second round, the robots also carried out inspections and spot tasks in autonomous mode, and were assessed on how easy an operator was able to intervene and take control. One mission also included an emergency alarm to assess the robots’ response. The practicalities of operating these vehicles were assessed too. One additional requirement for the challenge was that the robot had to return to its docking station NEWSBASE
June 2017
autonomously in order to recharge its batteries when it detected they were running low – perhaps one of the more simple tasks but one which would be vital to real-world operations. After a punishing week, the teams returned home and the judges began to deliberate their final verdict. The winner is… On May 11, Total announced that the winning team was the Austro-German ARGONAUTS. Aside from their excellent choice of name, Duflot said that their
June 2017
InnovOil Left: ARGONAUTS’ robot navigates the course. Below left: The winning ARGONAUTS team Below: A 3D model of the UMAD facility in Lacq, France
robot had proved to be the most capable of handling everything the competition threw at it. “The competition had very clear rules and at the end of the day when we compared the position of all the robots, ARGONAUTS was really the winner. The robot exceeded the requirements of the Challenge rules by obtaining the ATEX certification prior to the third competition. They had the most advanced level of technology maturity. It was very robust and they had a well-engineered system.” For the team, there is no doubt that the competition presented a formidable
challenge – speaking by email, ARGONAUTS told InnovOil that: “The mere complexity and difficult requirements made it most demanding project we have encountered in our professional robotic life.” ARGONAUTS had designed their system on a modular concept too, allowing for adaptations when confronted by future missions. Elements underneath the chassis also contributed to their victory – Duflot mentioned a very accurate positioning algorithm which allowed the robot a high degree of accuracy (to the centimetre) in navigation and performing readings. “The human-machine interface was really developed and easy to handle, and this is very important. It could also switch from one mode to another, from autonomous to remote, very efficiently,” she said. “All these points count toward a very reliable and robust robot. We need a good base to improve it and to move towards the robot of the future.” What now? With a winning partner chosen, Total is now planning the next phase of development. Duflot said that the group would begin an industrial pilot at one of it sites by late 2017 or early 2018. “This will be a way to NEWSBASE
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check how the robots work in the human environment. Our fields are developed for human [access], so it’s important to place the robot in a real site to be confident in its ability to work there. This is the next step for late this year or early next year.” ARGONAUTS added that externally, its design for the industrial pilot would not differ much from the challenge’s final version. “However, robustness, endurance and overall usability of the system will have to be greatly improved,” they said. Duflot declined to say whether any particular installations were in the running, but outlined that a prerequisite would be an asset with a good wireless system and 4G connection. “Also, somewhere we can study the behaviour of the robots in the first year. From there it will be case by case,” she added. The results of this pilot will determine the group’s longer-term strategy with autonomous robots, but thanks to the progress made over the past three years of the competition, much of the basic capability testing has been completed. “Our intention now is to move fast and to be able to use these types of robot as fast as possible,” she affirmed. As well as challenging them, the team has also developed a solid relationship with the supermajor. “Working with Total has been a great and enriching experience - after all it is a huge multinational oil and gas company and we are a consortium consisting of a small robotic company and an university institute,” they told InnovOil. “Still, we were always treated as equal partner in a successful project that will create mutual benefit for everybody involved.” For those eager to learn more, Total E&P and ARGONAUTS will be presenting findings from the experience at a number of conferences this year, and Duflot is confident that the industry will be interested in what they have learned. “Digitalisation is moving very fast and we have to think how to incorporate it and robotics at our sites,” she added. “We have some work to do, but clearly ARGOS is a very important first step, because the challenge provides us with very good information about what we can do with these autonomous robots.” n You can find out more about the ARGOS project via ANR at: www.agence-nationale-recherche.fr or on the ARGOS website: www.argos-challenge.com/en
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June 2017
MIT innovation means no sticking New chemical barrier formula could help prevent ice adhesion altogether
No ice, thanks Conventional strategies for dealing with hydrate formation include using heated pipelines, depressurisation or the use of chemical additives to break down any solids which have stuck. However, as is often the case with these things, prevention is far better than the cure. Doing so requires stopping the very first particles of hydrate from adhering to the pipe. “Once they attach, they attract other particles” of hydrate and a plug or deposit will begin to form quickly, Farnham explained in a statement. “We wanted to see
10 minutes
Increasing cyclopentane spreading parameter
C
HEMICAL barriers which help ketchup slide out of bottles could aid the oil industry with hydrate formation. Methane hydrates, also known as methane clathrates, are slush-like combinations of methane gas and water which form at the low temperatures and high pressures present at many offshore wellheads, and in pipeline infrastructure. This can cause serious issues with flow rates, with more severe blockages leading to pipeline ruptures or expensive shutdowns. Hydrate formation has also been partly blamed for the failure of the containment dome during the 2010 Deepwater Horizon disaster, when the frozen mixture blocked a vital outlet pipe, preventing it from redirecting the flow of leaking hydrocarbons to a tanker on the surface. A new paper by researchers at MIT proposes a new solution: an unreactive barrier chemical which prevents their formation altogether. The method was recently described in a paper published in the ACS Applied Materials and Interfaces journal, written by associate professor of mechanical engineering Kripa Varanasi, postdoc Arindam Das, and recent graduates Taylor Farnham and Srinivas Bengaluru Subramanyam. Their research was backed by Eni and awarded through the MIT Energy Initiative.
Zero minutes
how we could minimise the initial adhesion on the pipe walls.” Their system involves two steps: first the creation of a textured coating on the container wall, and then the addition of a lubricant that gets trapped by the texture and prevents contents from adhering. Coating the inside of the pipe with this material helps create a water-barrier layer along the pipe’s inner surface. This barrier layer can prevent the adhesion of any ice particles or water droplets to the wall and prohibits any build-up of hydrates. Unlike some chemicals which break down the plugs, this method is passive, and the barrier will not react with either the hydrocarbons or the surface of the pipe. Instead, the oleophilic coating will attract liquid hydrocarbons that are already present NEWSBASE
in the flowing crude oil, creating a thin surface layer that naturally repels water. “If the oil [in the pipeline] is made to spread more readily on the surface, then it forms a barrier film between the water and the wall,” Varanasi added. “We are using the liquid that’s in the environment itself,” rather than applying a lubricant to the surface, he continued. Because the key characteristic in hydrate formation is the presence of water, as long as this can be kept away from the pipe wall any build-up can be stopped, and as long as the hydrocarbons cling to the pipe wall, water will be prevented from touching it. Because hydrates form at extreme temperatures, the team used a proxy chemical – in this case cyclopentane – for their early lab tests. However, they have
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points for hydrates 120 minutes
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The coating forces water to bead up on the inner surface of a pipe rather than spreading out. This prevents the formation of ices that could lead to a clog in an oil pipeline or well. Image courtesy of the researchers reported that the test system has performed “very effectively,” with no hydrate adherence. In the conclusion to their paper, the authors note: “We anticipate that allowing the complete spread of nonaqueous, waterimmiscible films on solid surfaces will reduce gas hydrate adhesion, even under high pressure condition; however, further study is warranted.” The researchers were unavailable for comment on the next steps in their research, however given the seemingly effective results of their innovation, InnovOil imagines industry observers will be quick to take notes. n Contact: Karl-Lydie Jean-Baptiste Email: kjeanbap@MIT.EDU Web: www.news.mit.edu Phone: (617) 253-1682
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Inside Statoil’s dragons page 28
June 2017
Andrew Dykes speaks with Statoil’s corporate venture capital arm to learn more about the unit’s investment strategy, and what technologies hold the greatest promise for the NOC
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S the industry recalibrates itself amid stabilising prices, NOCs in particular are under pressure to identify where new innovations can help them drive efficiencies and reduce costs. Long considered a major player in technology development, Norwegian NOC Statoil has emphasised a number of methods to lead the charge. Statoil Technology Invest (STI) was set up in 2000 to help develop small to medium enterprises (SMEs) with new upstream technologies. Acting as the NOC’s venture capital arm, it invests in individual companies, as well as incubators and seed funds, with a view to producing not just a financial return to Statoil but also a measurable benefit to production or operations via the use of the SME’s technology. The department’s aim is to target innovative, high-impact upstream technology companies. That work involves three phases: identifying SME technologies which could be valuable, investing in them and helping them commercialise their products, and then selling profitable stakes on once that company has a sustainable business. While the classic venture capital investment model is to fund high-risk, high-growth early phase companies, STI’s managing director in Oslo, Kristin Aamodt, explains: “Corporate venture capital is
more than that. Our most important contributions are the know-how and customer perspective.” It is this combination of technical and financial guidance which the NOC believes gives its programme a competitive advantage. “What we’re looking for is any technology in this space that can increase production, reduce costs, reduce CO2 emissions or improve HSE – especially technologies with a low barrier to implementation that can produce results quickly,” she adds. In the LOOP STI has a sizable pool of resources and capital to draw from. The NOC’s 2017 research and technology budget is around 2.6 billion kroner (US$300 million), 50% of which will be deployed externally through collaborations, seed funding, academic work, so-called “LOOP” funding for specific projects and investments such as STI’s. Investment director in Stavanger Ingebrigt Masvie noted that a typical corporate investment would be in the region of US$1-10 million, for which Statoil would take a 10-40% position in the company. In general it avoids shares of 50% or over to avoid compliance issues, but it will hold board or observer positions in most of the companies it invests in. “We like to be active owners,” Masvie said. In addition, the ventures arm and its acquisitions can draw on expertise from
Viking Lady OSV, the first such vessel to use Corvus battery technology NEWSBASE
the 1,000 or so staff who work in the wider research and technology division. This twoway process helps both to refine the product offering for the SME, and ensure that Statoil sees maximum benefit as a customer. “We spend a lot of time in implementing the technology in Statoil, that’s where we see the greatest value in what we do as a company – getting these technologies in use. That’s where we can save a lot of money in our operations,” Aamodt said. STI backing also helps SMEs access facilities and personnel to help assess their technology. Investment analyst Erik Jakubowski explained that the company would “provide pilot wells and facilities in the testing process as well as expertise in testing criteria… We have the whole resource pool within Statoil to provide expertise.” These processes help develop the innovation through Technology
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Statoil building in Fornebu, Norway
Readiness Levels (TRLs) 1-7, with the aim of producing a proven solution that can be implemented by Statoil, and by other potential buyers. “In the end we aim to become the end customers and first commercial users,” he said. That is not to say that the group invests solely in equipment for its own use – the solutions chosen for any particular project must still be the most cost-effective for each job. “[SMEs] don’t get a preference because STI has invested. That’s what we say to our portfolio companies too – we can’t guarantee that Statoil will buy. But we think that by helping the companies understand he customer perspective, their chances are higher. This is why we also push companies to sell to other customers than Statoil. We encourage them to sell to the whole industry to develop a more sustainable company,” Masvie added.
Investment strategy STI has invested around US$20-25 million per year since 2010, and has around 20 companies in its current portfolio, all at various stages of maturity and the investment cycle. These range from ROVs, robotics and drilling equipment through to seismic companies and software providers; any upstream-focused technology is considered, provided it meets the principles set out by Aamodt above. STI’s ideal targets are not necessarily the most disruptive technologies on the market. The balance of cost and value is everything, and innovations with a long development timeline or high implementation costs are unlikely to be candidates, especially in the current price environment. A few companies in its current portfolio have positioned themselves as “first-movers” in their respective fields, Masvie noted. NEWSBASE
In terms of investment targets, companies in which STI invests tend to have already prepared a proof-of-concept. Masvie said that prior to this stage, developers were better candidates for LOOP or seed funding. It has also made investment in mature companies to support growth and keeps an open eye towards companies across the development cycle. “Every year we see about 300 deals or proposals, of which we invest in maybe 2 or 3,” he said. “We see a lot of the companies who do not get any support from us [too], but we do try to point them at incubators, local supporting structures in Norway… We try to help as much as we can.” The unit is guided by ambitious ROI metrics. “Our target is to bring implementation value to Statoil [of] the order of 20 times the investment we make in the companies,” he explains. “It’s never an
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exact figure but we try to estimate when we go into the company first time, and then we try to reassess this over the years.” The unit is also happy to look to the longer-term benefits of a technology rather than quick returns – Masvie confirmed that unlike many private equity or venture funds, STI did not have a fixed timeline for payback. Nevertheless, it maintains “pretty tough targets” to gauge financial returns upon exit, although the team did not specify exact criteria. Examples of the scale are there – in one instance, the company sold out of wireless reservoir surveillance company RESMAN for around 16 times its initial
InnovOil investment – suggesting that the venture can be every bit a revenue generator as a technology incubator. Throughout the process, however, selling out remains the goal. Once a technology is mature, the company has reached breakeven and shows sustainable growth with repeat customers, STI will move to offload its stake. “We are very much aligned with the founders and inventors to develop the company onto a final exit. We are not there for the duration,” Masvie confirmed. Driving change Some technologies have been of particular interest to the group. Drilling automation,
“What we’re looking for is any technology in this space that can increase production, reduce costs, reduce CO2 emissions or improve HSE” Kristin Aamodt, STI’s managing director in Oslo Picture: Statoil/Ole Jørgen Bratland
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the team says, has drawn a lot of attention and investment primarily because of the cost savings and efficiency gains it can offer. Actual deployment of these technologies has been muted, in part owing to the fall in prices, and in part because the scale of the challenge is formidable. “It is a huge step to get a fully automated drill floor, it needs a lot of new technology and by getting that to market we can help realise that ambition… Any pilots we have where we qualify a technology and it works, we have a piece of the puzzle,” Aamodt added, but recent pilots run on some Songa Offshore rigs suggest that progress is continuing. Masvie also points out often barriers to innovation lie in the structure of the industry, rather than a lack of capital. In cases where more disruptive technologies could affect the business models of service companies, SMEs can struggle to gain traction and support in the development stage, not to mention firm sales. He also drew particular attention to the service contract model, in which many service providers have little incentive to innovate. This was part of the rationale for STI’s investment in Corvus, a hybrid marine battery system aimed at reducing fuel use in offshore vessels. “If you look at supply vessels, most contracts today are based on Statoil paying for the fuel. [Even if a battery system can offer] a fuel reduction of 15-20%, why should a vessel owner install anything at all if Statoil is paying for the fuel?” STI therefore see its investment in new solutions as one method of driving this change in the wider service industry. A common complaint from many SMEs is that, despite finding enthusiasm in operators, they can struggle to turn this into actual support, pilots or sales. Aamodt said STI’s links to the rest of the NOC’s personnel meant that this was not the case in Statoil. “If you have a great idea I really think we can make a difference, because we are not happy to get stuck in middle management,” she affirmed. “We know who the paying customer is, we know who makes the decision and we ask that person.” Alongside a company-wide willingness to support innovation and deploy new technologies, the team believes that this can make a big difference to SMEs, and in turn, a big difference to the wider industry. n Statoil Technology Invest can be contacted through the division homepage at www. statoiltechnologyinvest.com
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Wintershall, YPF pick up pace in Vaca Muerta Longer, more productive laterals are driving down development costs and boosting production
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INTERSHALL has launched its second pilot project in the Vaca Muerta shale in Argentina. The German company said it had started drilling the first of three horizontal wells on its wholly owned Bandurria Norte block in the southwestern province of Neuquen. “The Argentinian shale formations are very promising,” said Gustavo Albrecht, managing director of Wintershall Energia. Wintershall, a unit of German chemical giant BASF, is the latest company to launch a pilot in Vaca Muerta, as the introduction this year of tax caps, pricing incentives and measures to cut labour costs improve the potential for putting the resources into production and making a profit. The Argentine and Neuquen governments, too, have vowed to build and improve highways, railroads, pipelines and ports to reduce logistics costs for moving inputs into the fields and products out. In comments to Neuquen Governor Omar Gutierrez, Wintershall executives said the Bandurria Norte pilot would cost US$120 million. Each well will be drilled for 1,500 metres with 15 frack stages, and the results should be available in February 2018, according to a statement by the provincial government. Bandurria Norte is adjacent to Aguada Federal, where Wintershall launched its
first pilot project in Vaca Muerta in 2015. The project involves the drilling of four horizontal wells, with the results due to be published by early 2018. Wintershall could invest up to US$2 billion in developing Bandurria Norte’s shale resources if the results of the pilot project are positive, the Neuquen government said. In its statement, Wintershall said the Vaca Muerta resources in the 107 square km block are located at depths of 2,700-3,000 metres. The German company said it was also investigating the shale potential of the Aguada Pichana and San Roque blocks, both of which will target Vaca Muerta. These and its other blocks are located close to Loma Campana, the biggest source of shale oil and gas to date in the play. Ten-dollar target Meanwhile, YPF is starting to drill longer horizontal wells in the play, as it looks to slash development costs by more than 20% over the next 18 months. The company has set a target of reaching US$10 per boe by the end of 2018 from a current US$13 per boe in Vaca Muerta, Pablo Bizziotto, the executive manager of unconventional resources, said last month at the SPE Latin American and Caribbean Petroleum Engineering Conference in Buenos Aires. “We are going to achieve this with longer wells after having reached a level of NEWSBASE
confidence and knowledge with horizontals of 1,500 metres,” he said. The company has focused on 1,500-metre horizontals, spending the equivalent of US$32 per boe in 2015. But as it has gained more knowledge of the play, it has reduced the development costs to US$13 per boe, Bizziotto said. For example, he said the company had cut drilling and completion costs to US$7.5 million on 1,500-metre horizontals and with up to 20 frack stages. That is down from US$16 million in 2012, according to company data. In the future, the company will shift its focus from drilling and completion costs to development costs based on barrels of oil equivalent. That is because it will be extending laterals, which cost more but are also more productive. Bizziotto said YPF had started drilling 2,500 metre laterals with more than 20 frack stages, and in the second half of this year it aims to do a 3,200-metre lateral with 40 frack stages. The latter will likely will cost US$1215 million for drilling and completion. To achieve further reductions in costs, the company is working on ways to move inputs, in particular frack sand, more cheaply to the fields, including by seeking lower taxes, Bizziotto said. YPF is the busiest operator in Vaca Muerta, where it is producing around 65,000 boepd, mostly through a joint venture with Chevron. n
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Working in the margins COMMENTARY
InnovOil speaks with Lloyd’s Register’s Steve Gilbert and Clinton Abbate about the potential of marginal field development in the US
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But according to a recent Barclays survey OR many oil-producing nations, of upstream operators, more than 77% marginal field development has of survey respondents said they expected become a new priority. As output onshore well costs in North America to falls from regions such as Malaysia trend down during the next 12 months – and the UKCS, there is new momentum despite more than 51% anticipating pressure to find technologies and commercial pumping pricing to rise over the same models to make these fields, and so-called period. Lloyd’s suggests that this indicates “small pools”, a viable economic prospect. there is some opportunity to leverage Yet similar trends are also emerging in low service costs to develop otherwise prodigious US onshore plays as E&P uneconomic marginal resources if operators’ companies weigh up their options in the balance sheets can tolerate additional risk. current price environment. While many operators continue to defer Lloyd’s Register Energy vice president investment into the US offshore assets (with of operations Steve Gilbert and Lloyd’s some having exited the market altogether, Register Drilling Services senior analyst e.g. ConocoPhillips), Clinton Abbate explained to investment in onshore InnovOil that in the current resources within the US (and foreseeable) market market is now beginning to “all developments could be show growth. Commodity considered marginal.” Each prices remain low but have development opportunity stabilised to a point where has to be assessed on its assets with low lifting costs can own merits and a bespoke now be brought to market at development plan created a profit with some reliance on for it. This will be influenced pricing support. by the potential size of the reserves, nature of “Success will come Progress through hydrocarbons, location, proximity to existing down to the right technology Economically, reductions in infrastructure and markets and approach, people capex, opex and through-life the risk/reward tolerance of and the lynchpin costs can independently or the developer. collectively drive development The current market has of trust” of marginal resources. By required many operators to Steve Gilbert, Lloyd’s lowering the cost to find, lift focus on developing only Register Energy viceand market hydrocarbons, their most efficient assets. As president of operations the pool of viable resources E&P budgets have declined is expanded, effectively over the last several years, increasing the operator’s access to profitable portfolio managers have then had to exercise reserves. additional discretion in CAPEX allocation For example, offshore production driving investment toward only the most facilities may represent an opportunity to margin-efficient projects. NEWSBASE
reduce opex through tighter management of shift intervals, leave policies and overall compensation structures provided that any revised policy still complies with applicable safety and labour laws. Field development strategies must wind their way through a full assessment that focuses not only on what is most technically appropriate but also on factors owing to timeline and resulting cost. Critical to this assessment is an understanding of the sensitivities, so that as the market continues to stabilise and rebound, sophisticated operators can identify when changes to key variables dictate action or a change in investment approach. Technology is the predominant driver for sustained decreases across the value chain, the pair added. On many recent calls with analysts, management teams acknowledge that many service companies are providing services at unsustainably low levels and that those costs will need to rise. Some already have – Halliburton and Schlumberger, for example, have already begun pushing up rates for onshore services. There is optimism about managing costs over the long term, citing technology as a key area of development where costs can be reliably managed. Abbate noted some
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COMMENTARY ConocoPhilips drilling site in the Eagle Ford
particular examples, the first of which is ‘Refracking,’ a trend becoming increasingly popular as operators revisit formations that were previously fracked to apply newer fracking methods and technologies. Socalled ‘well scouring’ also involves adding a specialised nutrient mix to water floods. This introduces microbes that attach themselves to hydrocarbon molecules, causing them to dislodge from the formation and flow to the wellbore. Microbial enhanced oil recover (MEOR) is therefore one technology which may see greater uptake as operators form their development plans over the coming years. “Success will ultimately come down to having the right approach, the right people and the lynchpin of trust,” Lloyd’s added. Establishing this quickly, and building understanding between specialist technology suppliers and operator will be fundamental to achieving it. This calls for a range of exemplary ‘soft skills’, along with outstanding technical expertise. More for less While marginal development is being considered by operators across the US, it is difficult to predict which area(s) will be most active, as the variables that drive
development decisions are dynamic. Beyond and there are many technical tasks to the breakeven costs, variables such as perform. Dedicated technical specialists prevailing royalty terms, production profiles undertake studies in areas that include and hydrocarbon splits all have seismic interpretation, an impact on total cost, Lloyd’s geological modelling, noted. petrophysical evaluation, Despite being slightly more reservoir modelling, well expensive to produce than modelling, system modelling conventional resources, US and production optimisation. shale plays have been the focus Maintaining production for of significant improvements as long as possible becomes in production efficiencies the overarching goal, with a over the last 12-18 months. relentless focus on production EOG Resources is just one optimisation and operational example, but shows the scale efficiency. “The US$100 play “One thing for sure is that of this overhaul: in 2016 the company posted a <1% the US$100 play book that book that has decline in production, despite has been used for the last 10 been used for the years is no longer helpful,” a 42% reduction in capex. It last 10 years is no the Lloyd’s team noted. “A accomplished this through driving massive reductions in longer helpful” successful development completion and production will depend on the skills, Clinton Abbate, Lloyd’s costs. experience and expertise Register Drilling Services Lloyd’s Register data of the team involved in its senior analyst suggest that other operators development.” n such as QEP Resources and ConocoPhillips have similar lead cost Contact: Jason Knights positions in the Bakken and Eagle Ford Tel: +44 (0)20 7423 1741 Shales respectively. Email: jason.knights@lr.org There are plenty of other factors too Web: www.lr.org/en/energy NEWSBASE
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Subsea 7 hails WND start The first phase of the West Nile Delta (WND) project, offshore Egypt, has been completed and first gas achieved, Subsea 7 revealed in its first quarter results. A statement on April 27 revealed the achievement. The company said it had been awarded the project in 2015. Subsea 7 said it “embraced new ways of working established in the industry downturn and its successful completion reflects the benefits of collaboration and early engagement”. Subsea 7 went on to say good progress was being made on the WND platform extension and tie-in, in addition to the Atoll work a presentation from the company put work on the first phase in the “very large” section, worth US$500 million, while the second phase of the WND is “major”, and worth more than US$750 million. The second phase is around 10% complete, it said, while Atoll is just over 30%. The total cost of the WND development is around US$12 billion. BP has said the WND project involves the development of 5 tcf (142 bcm) of gas and 55 million barrels of condensate. Production should reach 1.2 bcf (34 mcm) per day, around 25% of the North African country’s total production. Output comes from two concessions, North Alexandria and West Mediterranean Deepwater. The first phase of WND involves the Taurus and Libra fields, in water depths of 70 to 600 metres. The development consisted of nine wells being tied back to the Burullus facilities. Subsea 7’s work involved subsea umbilicals, risers and flowlines (SURF), topsides hook-up and engineering, procurement construction and installation (EPCI).
The second phase was awarded in February 2016, covering EPCI work on 12 wells, 80 km of umbilicals and 220 km of pipelines. A line will run from the site to the Idku terminal. The Giza, Fayoum and Raven fields will be tied back to the existing Rosetta plant, which will be modified, and to a new adjacent plant Edited by Ed Reed edreed@newsbase.com
Cambodia breaks ground on first refinery Cambodia held a ground-breaking ceremony on May 4 for the first phase of construction of a long-planned refinery that will be located on 385 hectares (3.85 square km) of land in the Kampot and Sihanouk provinces. China’s Great Wall International Engineering, an arm of state-owned China National Petroleum Corp. (CNPC), has been contracted to build phase one of the refinery, which will cost US$620 million and have a capacity to process 2 million tonnes of crude (40,000 bpd) when it comes into operation in 2019. A second phase for the refinery is meant to boost capacity to 5 million tpy (100,000 bpd) and is planned to come on stream in 2022. A third phase could be added after that. The current cost for the two-phase project is estimated at US$1.62 billion. Cambodia Petrochemical Co. (CPC) will operate the refinery. China Perfect Machinery Industry (Sinomach) is its joint venture partner. Together the two companies intend to establish 300 retail stations throughout Cambodia to serve the domestic market. Some US$300
million will be invested in building the retail network. The country’s refinery plans are aimed at reducing a 100% dependence on imported products. Crude feedstock for the refinery will be supplied from the Middle East, but Cambodia is hoping to develop its own offshore oil resources over the next few years. Singapore’s KrisEnergy is in the process of finalising a revenue-sharing agreement with the government that will enable work to start in Cambodia’s Block A in the Gulf of Thailand. It is estimated that Block A could be brought on stream in two years once the agreement is finalised. Cambodia’s demand for products is growing. In 2015, it used 1.8 million tonnes, which could be covered by phase one production. It intends for phase two to allow the export of up to 3 million tpy of products. While Cambodian officials have expressed their hope that domestically produced products will reduce retail prices, Cambodia’s Phnom Penh Post quoted Danish energy expert and CEO of Go4 Bunker Cambodia Tommy Christensen, who was attending the ground-breaking ceremony, as saying the new refinery might find it difficult to turn a profit as long as it relied on foreign crude oil imports. But he added that once Block A was producing crude the situation could turn around and put Cambodia on the global energy trade map. Edited by Andrew Kemp andrew.kemp@newsbase.com
NPD awards new technology agreements To ensure sufficient capacity to be an even better champion for developing new fields and improving recovery from producing fields, the NPD has awarded framework agreements to eleven supplier firms representing various technology areas. The contractors will provide professional assistance within their specialty areas, and the NPD will utilise this expertise in its work to follow-up developments on the Norwegian shelf and on operational fields. The framework agreements include (supplier award in parentheses): • Subsurface technology, reservoir geology and reservoir technology (AGR Petroleum Services AS, Ross Offshore AS and Larsen Reservoir ApS)
Graphic: BP
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• Drilling and well technology (AGR Petroleum Services AS, Ocean Maxwell AS and Acona AS) • Development technology and operation of installations and facilities (Rambøll Oil & Gas AS, Acona AS and Aker Solutions AS) • Seabed technology and infrastructure (Acona AS, Aker Solutions AS and Genesis Oil and Gas Consultants Norway AS) • Land facilities, technology, infrastructure and capacities (Kværner AS, Aibel AS and Aker Solutions AS) • Disposal of facilities (Kværner AS, Dr Techn Olav Olsen AS and Genesis Oil and Gas Consultants AS) The tender competition targeted external companies with relevant technical expertise. The parallel framework agreements have a duration of two years, with options for extending the agreements with one plus one year. NPD
CNOOC to award Huizhou EPC contracts CNOOC Ltd is understood to be on the verge of awarding to two separate engineering, procurement and construction (EPC) contracts for a development platform to be installed at the Huizhou 33-1 oilfield in the shallow waters of the South China Sea. The company has already issued letters of intent (LoIs) to Shenzhen Chiwan Sembawang Engineering (CSE) to build the platform’s jacket and to COOEC-Fluor Heavy Industries (CFHI), a joint venture between China Offshore Oil Engineering Corp. (COOEC) and the US’ Fluor, to build the topside. Industry officials have said construction work is expected to start in the third quarter and finish in the second quarter of 2018. First NEWSBASE
oil is scheduled for the first quarter of 2019. The platform will handle water and oil separation before production is then sent to the Hai Yang Shi You 115 floating production, storage and offloading (FPSO) vessel for further treatment. The floater has been used for other Huizhou oilfields, including Huizhou 26-1, Huizhou 32-2 and Huizhou 25-8 over the last few years. The fields are part of a larger Huizhou oil complex. CES and CFHI are already working on another platform that will help develop Huihzou 33-1. The platform, which is located at Huizhou 32-5 and will include top sides and jackets, will be completed towards the end of this year. Located in 113-116 metres of water, about 170 km southwest of Hong Kong, Huizhou 33-1 is one of nearly two dozen oil and gas projects CNOOC Ltd is developing in the South China Sea, East China Sea and Bohai Bay. CNOOC Ltd is keen to bring more oilfields into play in order to offset production declines
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from existing fields. Output is projected to fall to 450-460 million boe (1.23-1.26 million boepd) this year from last year’s 477 million boe (1.31 million boepd). In early April, CNOOC Ltd’s parent, China National Offshore Oil Corp. (CNOOC), invited foreign firms to bid for 22 blocks in the northern part of the South China Sea. The blocks cover 47,270 square km and include 16 licences in the eastern part of Pearl River Mouth Basin, two in the western part of Pearl River Mouth Basin and four in the Beibuwan Basin. Edited by Andrew Kemp andrew.kemp@newsbase.com
Centrica to treble output from Chestnut field Centrica aims to treble output from its decadeold Chestnut oilfield in the UK Central North Sea by spending GBP35 million (US$45.65 million) on a new production well. Chestnut, which is located in UK Block 22/2a, currently yields around 4,000 bpd from two wells, but will add around 10,000 bpd once the latest hole is spudded by Paragon’s MSS1 semi-submersible rig. That would lift output to around 14,000 bpd gross, Centrica said, compared with the average of around 5,800 bpd that was extracted in June 2015, and 7,000 bpd produced as of September 2013. In light of the new investment, Centrica has extended the contract for Teekay’s 25,000 bpd capacity Hummingbird Spirit FPSO by three years until 2020, which has secured around
70 jobs. The Hummingbird Spirit can store more than 200,000 barrels of crude, and utilises several flexible risers to dispatch oil. Centrica’s asset manager for the Central North Sea, Nigel MacLean, said: “Fields like Chestnut underline the importance of maximising the potential of as many North Sea fields as possible, whether they be major finds or small pools.” Chestnut launched in 2008 and was initially expected produce 7 million barrels over three years, but ongoing investment has seen it export 20 million barrels over the last decade. Centrica upped its recoverable reserve estimate for Chestnut to 18 million barrels in 2013 after drilling a water injection side-track to maximise production efficiency. The company owns an 83% operative stake in Chestnut alongside Dana Petroleum, which owns 17%. Faroe Islands explorer Atlantic Petroleum once owned a 15% stake in Chestnut, but withdrew from the development in 2015 amid a strategic review to contend with lower oil prices. Most of the deposits in the UK North Sea are maturing fields which initially struggled to adapt when crude prices crashed by 50% in 2014. However, the UK outlook looks rosier following efficiencies which have halved operating costs to US$15.30 per boe from US$29.70 per boe two years ago, according to Oil and Gas UK’s 2017 report released in March. The industry representative said offshore oil and gas output in 2016 had risen by an annual 5% to 1.72 million boepd, and predicted yields could grow further by 2019 if efficiencies were maintained and new projects launched as planned. Edited by Ryan Stevenson ryans@newsbase.com
Centrica’s Hummingbird Spirit in the Chestnut field
Finland
Norway Sweden
Lubmin, near Greifswald
Poland
Russia
Germany
M² Subsea wins Nord Stream contract M² Subsea has secured its first contract award valued in excess of one million pounds. The project will see the firm supplying the Go Electra vessel, ROVs and personnel to support survey work on the world’s longest subsea pipeline system. The company, which has bases in Aberdeen and Houston, has been subcontracted by Next Geosolutions, an independent geoscience and engineering service provider, to deliver the campaign in the Baltic Sea for the Nord Stream 2 project. Next Geosolutions was appointed to carry out unexploded ordnance identification (UXO) surveys on the two new pipelines. The campaign for Nord Stream 2, an extension of the world’s longest pipeline, will be undertaken in an area noted for munitions discoveries following the end of World War II. To support the 90-day project on the Nord Stream 2, M² Subsea has signed its first charter agreement for the multipurpose support vessel (MSV) the Go Electra, which recently successfully completed its first fiveyear class inspection. The scope of work will be project managed from Aberdeen and will see the MSV deployed from Hanko in Finland, and supported by 15 of M² Subsea’s personnel who will carry out the UXO identification work utilizing a Triton XLX 2 Work Class ROV and a Mohican 5 observation/ inspection class ROV from the firm’s fleet of 28 assets. M² SUBSEA
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NEWS IN BRIEF
Proserv Norway secures decommissioning awards
Moscow approves Rosneft’s FEPCO project
Energy services company Proserv has recently been awarded three contracts worth a combined value of more than $2.5million (approx. 21.5m Norwegian Krone) for decommissioning work in the Norwegian North Sea. The firm’s Stavanger facility will provide cutting services as part of a full severance package covering subsea and topside work. Compared to more traditional approaches, the cutting technology solutions deployed by Proserv can save hours in well severance and plugging, which can lead to significant savings in day rates over a campaign. These awards build upon decommissioning successes for the company globally in recent months with around $8million worth of work secured in Asia Pacific, the UK and Gulf of Mexico. As part of the decommissioning workscopes, Proserv will provide abrasive cutting, diamond wire cutting, grout removal and dredging services.
RUSSIA’S construction and engineering watchdog Glavgosexpertiza has approved the design plans for Rosneft’s new refinery and petrochemical complex near Nakhodka on the Sea of Japan. “Having studied the materials of the project, Glavgosexpertiza has concluded that the results of an engineering survey and the design documentation comply with the requirements of technical regulations and other statutory requirements,” the regulator said in a statement on May 12. “The construction and commissioning of the facility, according to the draft approved by Glavgosexpertiza, will take place in two stages,” it added. The Far Eastern Petrochemical Co. (FEPCO) project’s first phase is an oil refinery, which will have an annual throughput capacity of 12 million tpy (241,000 bpd). The second phase of the refining cluster will feature a petrochemical complex with a total capacity of 3.4 million tpy (68,300 bpd). The two stages are due for completion in 2020 and 2022 respectively.
PROSERV
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Rosneft has previously said, however, that the capacity of both the refinery and the petrochemical complex could be doubled by 2028, should market conditions justify the expansion. In June last year, Rosneft signed a heads of agreements (HoA) with ChemChina, handing the Chinese firm a 40% interest in FEPCO in exchange for proportional financing for the project. The plant’s total construction cost across the first two stages is estimated at around 660 billion rubles (US$11.7 billion). FEPCO’s oil refining arm will produce mainly gasoline, diesel, kerosene and bunker fuels for local buyers in the Primorsk and neighbouring regions as well as for export to the Asia-Pacific market. The petrochemical plant, meanwhile, will be geared towards the production of ethylene, propylene and other related products. Last month, the FEPCO project was at the centre of a dispute between Rosneft and national gas rival Gazprom over the supply of the gas required to power the plant. Gazprom said that it was prepared to move the necessary volumes to FEPCO but the gas should be derived from Rosneft’s fields. The Russian oil major, which holds a 20% stake in the nearby Sakhalin-1 project, rejected the claim, pointing to Gazprom’s fields in the Russian Far East, which were acquired without
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government tenders. Deputy Energy Minister Kirill Molodtsov said last month that the issue would be resolved by the end of June this year. FEPCO will be fed with oil from the Eastern Siberia-Pacific Ocean (ESPO) pipeline system. Edited by Joe Murphy josephm@newsbase.com
Japan to store gas at depleted fields THE Japanese government plans to utilise depleted gas fields as imported natural gas storage sites to ensure a stable and cheaper supply, a local media report said. The reported move comes as demand for LNG rose sharply in Japan as an alternative fuel to atomic power in the wake of the 2011 disaster at the Fukushima No. 1 NPP. Natural gas is one of resource-poor Japan’s main import items along with crude oil and coal. Japan imports natural gas in the form of LNG and is by far the world’s largest LNG importer. The Japanese mining law currently has no provision regarding the storage of imported natural gas at depleted gas fields. The Ministry of Economy, Trade and Industry (METI) reportedly intends to interpret the law as allowing imported LNG to be stored at depleted gas fields after being regasified. METI is preparing to explain – and get approval for – the new legal interpretation at a meeting of an experts’ panel convened as early as this month, the Mainichi Shimbun, a major national daily, reported in May. The use of depleted gas fields as storage sites
will allow the country to import natural gas in large quantities when international prices are declining and then to release the stored gas to the domestic market when international prices are rising, the paper said. In Japan, depleted gas fields are concentrated in Niigata Prefecture on the Sea of Japan coast. The central Japanese prefecture is also home to three LNG import terminals, including Inpex’s Naoetsu terminal in Joetsu City. The biggest Japanese energy developer put into operation the Naoetsu terminal in December 2013. The terminal has an annual capacity of 1.5 million tonnes. LNG received there is regasified and supplied via Inpex’s pipeline network. For many years, Inpex has supplied natural gas produced at a field in Nagaoka City, Niigata Prefecture to gas and other companies in the Kanto region, including Tokyo, via its pipeline network. Inpex is the operator of the Ichthys LNG project in Australia and the Abadi LNG project in Indonesia. The company will receive LNG from the two projects at the Naoetsu terminal. The Naoetsu terminal consists of two 180,000 cubic metre storage tanks. Inpex has said that it is possible to install one more in the future. Edited by Richard Lockhart richardl@newsbase.com
ENAP targets tight gas in Chile Chile’s state oil company ENAP is preparing to carry out its first horizontal drilling for natural gas resources in a tight play this year, as it seeks to reduce imports over the long term. The company will drill the multi-frack stage
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well with US-based ConocoPhillips, its partner on the project in Magallanes, a basin in the far south of the country. The horizontal well will be drilled “by the end of the year,” ENAP’s general manager, Marcelo Tokman, said last month at ARPEL 2017, a Latin American and Caribbean oil and gas conference in Punta del Este, Uruguay. ENAP and ConocoPhillips teamed up on the project last June, committing to invest US$100 million in the first four years of the project. They are exploring the tight gas potential of the Coiron block in the Magallanes Region, a source of conventional oil and gas encompassing both onshore and offshore blocks. Tokman said the partnership with ConocoPhillips, one of the world’s biggest shale
June 2017
InnovOil
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NEWS IN BRIEF
Bibby Offshore awarded TAQA contract
producers, had brought it knowledge about drilling in unconventional plays, helping to speed up its learning and cut per-well costs by 50% over the past two years. This has come through incorporating pad drilling and new techniques, among other things, he said. The horizontal drilling should reduce costs further, he added. ENAP is seeking to ramp up gas production from Magallanes to supply that region and Methanex, a Vancouver, Canada-based company that uses the gas as feedstock for making methanol, a raw material for manufacturing chemicals. Methanex has a methanol complex in Magallanes that has run at below capacity for much of the past decade given that Argentina has restricted gas deliveries to deal with shortages at home. The cutbacks have also hit the rest of Chile, which had been buying up to 20 mcm per day of gas from Argentina as recently as 2004. In response, ENAP started increasing local drilling for gas. The country also ramped up renewable energy capacity and built two regasification terminals for importing LNG. A third LNG regasification terminal is planned. In the long term, however, Tokman said an increase in tight gas production from Magallanes could help reduce and eventually replace the LNG imports. Magallanes has over 8 tcf (235 bcm) of tight gas resources, according to a 2016 estimate by the US Geological Survey (USGS).
Bibby Offshore has been awarded a significant contract with TAQA for subsea construction works in the Eider field, located 184km northeast of Shetland. With offshore operations to be completed this summer, the six month contract will see Bibby Offshore adopt a multi-vessel approach, utilising its subsea support and construction vessel Olympic Ares, and its diving support vessel, Bibby Polaris. The project comprises the connection of the existing Otter Production pipeline to the existing Eider Oil Export pipeline, and connection of the existing Tern-Eider water injection pipeline to the existing Otter water injection pipeline using subsea bypass spools. Bibby Offshore will provide spool piece metrology, barrier testing, removal of existing production and water injection spools and pre-commissioning support. The team will also manage procurement, fabrication and installation of new bypass spools. Barry Macleod, UKCS managing director at Bibby Offshore said: “Our multi-vessel approach enabled the project team to tailor our capabilities to TAQA’s requirements, which plays a key role in demonstrating our ability to successfully deliver a variety of workscopes.” BIBBY OFFSHORE
Schlumberger signs MoU with Saudi Aramco Schlumberger HAS signed a memorandum of understanding with Saudi Aramco to develop an In-Kingdom Total Value Add roadmap, in alignment with the Kingdom’s economic vision for 2030.
Edited by Ryan Stevenson ryans@newsbase.com
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The Schlumberger In-Kingdom Total Value Add roadmap includes the creation of jobs and enables development opportunities for Saudis in oil and gas services and related sectors. The roadmap also strengthens the deployment of Schlumberger technology, reduces regional delivery times for key products and services, and increases local capacity and deployment capabilities. “For more than 75 years, Schlumberger has supported Saudi Aramco and the Kingdom of Saudi Arabia’s oil and gas industry through an unwavering commitment to train and develop Saudi talent, and through a comprehensive portfolio of technologies, execution of integrated projects, and world-class research collaboration,” said Paal Kibsgaard, Chairman and CEO, Schlumberger. in 2006, Schlumberger pioneered its Dhahran Carbonate Research Center, located close to King Fahd University with a focus on Geology and Rock Physics and Production Completion and Recovery projects in the Middle East region. In addition, Schlumberger has in-country manufacturing capabilities to support the deployment of its technology, products and services. In 2016, Schlumberger inaugurated its Middle East Center for Reliability and Efficiency (CRE), which collocates maintenance and product center sustaining experts engaging in industry–leading maintenance processes. The Middle East CRE is the largest state-of-the-art facility in the Schlumberger network. SCHLUMBERGER
3D survey in Delaware FAIRFIELDNODAL and Schlumberger are teaming up for a major 3D survey in the southern Delaware Basin – part of the Permian Basin – in West Texas. Phase 1 of the Coyanosa Survey will cover roughly 306 square miles (793 square km) in Texas’ Ward, Reeves and Pecos counties.
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NEWS IN BRIEF
The companies’ entire area of mutual interest encompasses around 1,100 square miles (2,849 square km). The data resulting from the first phase, for which non-exclusive licences will be available, will tie into existing FairfieldNodal and WesternGeco 3D data. It will provide customers with contiguous data coverage in the southern Delaware Basin, said the companies in a press release. WesternGeco is a geophysical services company owned by Schlumberger. “Under the present oil and gas market conditions, collaborations allow us to quickly and economically provide our customers not only high-end imaging solutions, but also an in-depth knowledge of the multiple reservoirs and drilling hazards that exist in the area,” said WesternGeco’s president, Maurice Nessim, in a statement. Permitting for the project is being conducted by International Technologies Management (ITM) and is “well under way”, while field operations are expected to begin shortly, said the companies. FairfieldNodal has already begun designing and testing field acquisition parameters. Processing will be provided by WesternGeco. Other contributors include Dawson Geophysical, which will handle field acquisition, and TRNCO Petroleum, which will be the project manager. Data will be jointly licensed by FairfieldNodal and WesternGeco.
Schlumberger recently announced that during the first quarter of 2017, WesternGeco completed the purchase of a 3D wide-azimuth multi-client survey in West Texas covering 253 square miles (655 square km) in the southern part of the Permian Basin. This brought its total coverage in the area to 655 square miles (1,696 square km). Edited by Anna Kachkiva annak@newsbase.com
Bechtel wins Tahrir Petrochemicals contracts US-BASED Bechtel has been awarded a project management contract by Egypt’s Carbon Holdings to oversee construction of a multibillion dollar petrochemicals complex at the Suez port of Ain Sokhna. The award is seen accelerating progress on the financing of the long-delayed scheme. The client has been indicating expectations of securing coverage from US and other export credit agencies (ECAs) for several years. The search for debt and equity finance for the project, set to become the country’s largest in
NEWSBASE
the sector, coincided unluckily with a period of political turmoil and loss of investor and lender confidence. Contracting difficulties have also slowed progress. Bechtel was additionally appointed to carry out the main contract on an associated expansion of the local developer’s existing facilities at the site, at the southern end of the Suez Canal. Bechtel announced on April 19 the award of a project management services (PMS) contract for the development of the Tahrir Petrochemicals complex. It provided neither detail on scope, beyond that the mandate entailed “oversight of project execution and contractor performance”, nor on timeframe. Total project costs were stated in the latest announcement as US$10 billion – including the brownfield expansion. The costs for the Tahrir plant alone have most recently been put by the company at around US$7.4 billion, double the US$3.7 billion first mooted. The complex will comprise a 1.5 million tpy naphtha cracker and derivatives units producing 1.35 million tpy of high density polyethylene (HDPE) and linear low density polyethylene (LLDPE), 880,000 tpy of propylene, 880,000 tpy of polypropylene (PP), 250,000 tpy of butadiene, 350,000 tpy of benzene and 150,000 tpy of gas oil. Edited by Ian Simm ians@newsbase.com
June 2017
InnovOil
What next …?
To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections
To find out more about how Enpro’s ESSI FAM technology could aid your subsea well development, contact Ian Donald on +44 (0)1224 974 000 or at idonald@enpro-subsea.com ; alternatively, you can speak with Adam Hudson in Houston on +1 713 502 0363, or via ahudson@enpro-subsea.com If Trelleborg and SubC’s successful replacement of buoyancy modules on a live riser could enable you to save time and money, contact Andy Hey on +44 (0)7876 885 290, or email andy.hey@trelleborg.com You can find out more about Total’s ARGOS project via ANR at www.agence-nationale-recherche.fr or on the ARGOS website www.argos-challenge.com/en For more information on Baker Hughes’ DEEPFRAC™ deepwater multistage fracturing service contact Melanie Kania on +1 (0)713 439 8303 or email melanie.kania@bakerhughes.com SMEs and innovators with new technologies looking for investment can reach Statoil Technology Invest through the division homepage at www.statoiltechnologyinvest.com For further information on MIT’s hydrate-busting coating, speak with Karl-Lydie Jean-Baptiste at: kjeanbap@MIT.EDU To speak with Lloyd’s Register regarding US marginal development, you can contact Jason Knights at +44 (0)20 7423 1741 or via jason.knights@lr.org
NEWSBASE
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CONTROL Solutions POWER AND Umbilical
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SIXTH SENSE flare
Lumasense’s system monitoring
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“We were pleased with the immediate interest that our on article Kongsberg attracted.” Page 14
“The article Oxford Catalysts Group Maritime’s Munin AUV is excellent”
Mark Hampton, Manager of Exploration and Technology, Shell Exploration and Production Inc. Published by
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