InnovOil 2016 Annual Review

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NEWSBASE

Bringing you the latest innovations in exploration, production and refining 2016 Annual Review

December 2016

Blast Off 2017

NewsBase editors look ahead Page 16

The year in review

The best of InnovOil Page 23

Take Claire

The future of GHG monitoring Page 6

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Annual 2016

InnovOil

page 3

Inside Emissions possible

6

Making light work

8

Satellite monitoring for oilsand GHGs

Bronswerk Heat Transfer’s talks downstream redesign

Contacts:

Island in the sun

Media Director Ryan Stevenson ryans@newsbase.com

Riserless coiled tubing gets heavy

10

Dalmatian developments 11 Subsea Integration Alliance grabs contract

Media Sales Director Charles Villiers Email: charlesv@newsbase.com

On the radar

12

Deepwater design

14

2017 Global Outlook

16

BEST OF 2016

23

FLI guy

24

See snakes

27

Cracking the case

28

Thermite be giants

32

3D printing rocks

34

Spacequakes

36

HUD on

39

Look closer

40

Powered up

43

Coming unstuck

44

Pooling knowledge

46

Contacts

50

GustoMSC’s new Scyllax drillship

Editor Andrew Dykes andrewd@newsbase.com

NewsBase editors look ahead

NewsBase Limited Centrum House, 108-114 Dundas Street Edinburgh EH3 5DQ

Well-SENSE’s fibre intervention

Phone: +44 (0)131 478 7000

Eelume robots to tackle IMR

www.newsbase.com www.innovoil.co.uk

Gas cracking without the CO2

Design: Michael Gill michael@michaelgill.co.uk www.michaelgill.eu

Interwell’s P&A proposal

Smart rocks with embedded sensors

Spotting earth movements by satellite

Navy-developed smart helmets

TSC Inspection’s ACFM® technique

The Subsea Hub from EC-OG

Visuray’s downhole x-ray imaging

The SeaCaptaur production system

NEWSBASE

ITF launches Innovation Network to shine a light on SME Technology Development for the Oil & Gas Industry

The aim of the ITF Innovation Network is to provide an effective mechanism for technology developers to promote their technology development efforts to ITF members and the wider industry.

This will be an active and evolving community where we will encourage discussion and engagement on technology qualification, field trials, joint industry projects and new technologies that can be quickly implemented on projects.

Please register to join our community of Technology Developers, https://network.itfenergy.com or contact a member of our team at innovate@itfenergy.com for more information.

FACILITATE COLLABORATE INNOVATE

www.itfenergy.com

Annual 2016

InnovOil

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A note from the Editor If 2016 has proved anything with any certainty, it is that nothing is certain.

Such a paradox is unlikely to inspire confidence in the oil market – yet it is borne out in a year that has seen everything from collaboration to competition, and even collapse. There were glimmers of hope with news of OPEC’s agreement to cut output in November, but the outlook for 2017 remains cautious.

A planned US$28 billion mega-merger between Halliburton and Baker Hughes was called off in the spring because of antitrust concerns. General Electric swooped in a few months later with its own proposal to merge its oil and gas wing with Baker Hughes, with the deal now going through the requisite regulatory hoops. If the deal succeeds, it will further blur the lines between the oilfield equipment manufacturing process and the services element.

Deals like this are interesting in terms of how the industry regards innovation. GE has already experimented with an uptime-only BOP rental agreement with Diamond Drilling, and further tie-ups in other industry sectors could mean a shift in the landscape of services provision and technology development. With lower cost and increased efficiency being the key drivers of any technology deployed in

oilfields today, new integrated businesses may be better positioned than most. More M&A activity is probable in 2017.

The hydrocarbons industry has looked outward to new ideas this year more than in any other since I have edited InnovOil. ‘Technology Transfer’ is not a term confined to afternoon conference sessions, but something which is now under way across the industry. We have seen drones deliver cargo to vessels, new long-distance fibre-optic monitoring, x-rays used for downhole imaging and much more. This is a trend that I hope to see continue next year.

In this our 2016 Annual Review we take a look back at the most interesting tech developments covered this year.

The NewsBase editorial team also looks back on the year’s regional trends and innovations, and looks ahead to what to expect in 2017.

I would like to thank all the inventors and innovators, professors and professionals that have featured in the magazine this year. InnovOil will return in the New Year ahead of the annual Subsea Expo in Aberdeen, where we look forward to meeting many more technology developers with stories to tell.

All that remains is for me and the team is to wish you all a merry Christmas and all the very best for a prosperous 2017.

Andrew Dykes Editor

NEWSBASE

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Emissions possible – monitoring GHGs from space

InnovOil

2016 Annual

Oilsands JIP COSIA and satellite monitoring firm GHGSat have teamed up to examine whether nano-satellites may be the future of low-cost emissions compliance at oil and gas assets

O

il and gas companies are literally going out of this world in a new attempt to measure greenhouse gas (GHG) emissions from their facilities. A dedicated satellite, named Claire, has been developed to measure CO2 and methane emissions from single sources – with high accuracy, frequently and at a relatively low cost.

Should it prove successful, more oil and gas operators could use such technologies to understand emissions from their assets better, helping them to comply with government regulation more easily and work towards reducing their output of GHGs. Montréal-based GHGSat has launched a year-long demonstration programme of the small satellite’s capabilities. Claire has been in space since late June, orbiting the earth and measuring emissions from Canadian operators. It is billed as the world’s first satellite capable of monitoring GHG and air quality emissions from a single industrial site. The satellite has so far taken some 500 measurements from about 500km above the earth’s surface.

GHGSat, which describes itself as a global emissions monitoring company, has clients that range from Hydro Québec to Canada’s Oil Sands Innovation Alliance (COSIA), a workgroup consisting of companies that share technologies to reduce

the environmental effects of oil sands operations. Members of COSIA include Imperial Oil, Canadian Natural Resources, Royal Dutch Shell and Suncor.

The joint industry project (JIP) with COSIA members is to investigate the use of satellite technology to provide more accurate and frequent measurements of fugitive GHG emissions from tailings ponds and mine faces.

NEWSBASE

Many sites in sight “We can do this [monitoring] at a cost that industrial operators can afford,” said GHGSat president Stéphane Germain, in an interview with InnovOil. Using this system, emissions can be measured accurately from a source as small as a single well-pad. So far, individual emissions have been measured from oil and gas-related facilities ranging from oil sands mines and tailings ponds to fracking basins, refineries, compressor stations and LNG terminals. Emissions have also been measured from a wide variety of sites in other sectors, ranging from landfill facilities to volcanoes, with one satellite capable of monitoring GHGs at more than 1,000 sites per year.

National space agencies such as NASA, the Japan Aerospace Exploration Agency and the European Space Agency all have satellites that can measure GHG emissions, but their resolution is far larger than Claire’s.

Their purpose is to inform larger, macrolevel climate-change models, says Germain.

By contrast, Claire has a high spatial resolution of just 50m by 50m, and is a far smaller satellite: measuring 450mm x 300 mm x 200mm, it is technically a nano-satellite, about the size of an ordinary microwave oven. Whereas national space agency satellites typically weigh hundreds

Annual 2016

InnovOil

Claire satellite undergoing thermal vacuum tests. The glowing lamps surrounding the satellite simulate heat from the sun’s light.

of kilograms, Claire is just 15kg, slashing the cost of building and launching her from hundreds of millions of dollars to a figure in the “single millions”, says Germain.

Claire‘s payload includes two sensors: a 2D wide-angle Fabry-Perot imaging spectrometer, and a new, innovative clouds and aerosols sensor. The miniature spectrometer is used to measure wavelengths of light spectra – gases absorb light at specific wavelengths, creating a ‘spectral fingerprint’ for each gas, GHGSat explains.

The system can find these fingerprints using sunlight, and measures the brightness of those fingerprints to determine, using algorithms, how much CO2 and methane are present in the field of view of the satellite.

A technique called ‘dispersion modelling’ is used, whereby known sources of emissions are combined with meteorological data to determine the concentration and location of emissions in the atmosphere at a given time.

This means that no devices or personnel are required to perform measurements on the ground.

Claire was launched on June 22 from India’s Satish Dhawan Space Centre, and orbits the earth every 90 minutes or so, travelling at more than 7 km per second.

Claire is expected to operate for 5 years, and will burn up in the atmosphere after the mission is complete.

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GHGSat’s satellite is launched from India’s Satish Dhawan Space Centre

Some 40 people were involved in the development, build and launch of the satellite. At present, GHGSat currently has some 10-15 staff and will soon ramp up to 40 again as its starts on its next satellites.

A new standard?

The project is as much about effective and economic compliance as it is about innovation. In Alberta, for example, companies with oil sands developments are required to measure and report emissions to the provincial government for compliance purposes. Oil sands account for 9.3% of Canada’s GHG emissions and about 0.13% of global GHG emissions. Canada, home to 0.5% of the world’s population, produces about 2% of global CO2 emissions. Sources of GHGs in the oil sands include so-called fugitive emissions, uncontrolled leaks and gas released into the atmosphere.

Without space-age technology such as Claire, oil sands companies must place a physical ‘flux chamber’ or large hood over a tailings pond or above a mine to capture and measure the gases they emit. Even so, the total plant emissions are only an estimate.

“This existing measurement method has a significant degree of uncertainty, 50% or more,” says Glynis Carling, a senior environmental advisor at Imperial, in an article on COSIA’s website. “It’s also costly NEWSBASE

and there are associated safety risks, since workers must conduct the measurements directly on the ponds or close to mine faces.”

Claire also processes results more often than traditional methods. Passing over the oil sands every two weeks or so, the system offers a flux estimate every two to four weeks – compared with a single estimate each year using the current process.

The cost of measuring emissions conventionally is considerable. A survey of a single landfill gas facility might cost US$20-50,000, said Germain. He declined to comment on the cost of monitoring in the oil sands.

However, the added efficiency of measurement from space could be even an even greater asset. “This technology could also help us determine the source and cause of some of the ‘noise’ we see in current measurements,” Carling explains at COSIA. “And if we know what the cause is, we can work to reduce emissions from that specific source.”

As with operations on the ground, weather can be one inhibiting factor. Claire can measure emissions in Alberta when conditions are clear enough, or about half the time, says COSIA. “The instrument can’t see through clouds,” explains Germain.

“However, we don’t need a completely clear sky. As long as we can see the site and the plume of greenhouse gases downwind from the site, then we can perform the measurement.”

Gases can be monitored with a precision up to part per billion, says COSIA. Because the project is still in the demonstration stage, the measurements of oil sands GHGs are then compared with flux chamber data.

Direct measurements can be analysed to determine emission rates, or they can be used for threshold detection, such as when precisely emissions exceed a certain amount.

Thus far, Claire’s measurements have been found to be accurate, Germain notes. Having been in orbit for first six months, “she is performing beautifully.”

With emissions compliance only set to become stricter across most of the world as governments push for greater decarbonisation, such solutions may become more commonplace. Indeed, according to COSIA, if the project is successful, the technology has the potential to be quickly adopted as “the industry standard,” for emissions monitoring. n

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InnovOil

2016 Annual

Bronswerk heats up Iranian downstream plans Bronswerk Heat Transfer explains how a serious design diet enabled dramatic cost reductions at an Iranian petrochemical plant

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or obvious reasons, a large number of upstream and downstream projects have been put on hold in Iran over the last few years. One such project was the Bid Boland II Gas Processing Project, scheduled to be built in Khusestan Province in the country’s southwest.

Although awarded to EIED (Energy Industries, Engineering & Design) in November 2007, Bid Boland had been postponed three times over the past few years.

It was only in 2015 that a new owner – Persian Gulf Petrochemical Company – fully revived the project. This allowed the engineers of bronswerk to redesign a part of the proces in such a way that serious reductions of plot space, material and operational costs could be realised, a substantial advantage of involving Bronswerk when changes like the ones explained in this article can still be made.

This multi-billion euro development consists of a refinery with a processing capacity of 57 mcm per day of sour and sweet gases from four gas and NGL plants in the region. Additionally, it includes 600 km of feed and product pipelines, an export terminal in Mahshahr and a 600-unit residential camp, as well as industrial and non-industrial buildings and related facilities.

Production capacity at the refinery would consist of 15 bcm per year of sweet gas, 1.48 million tonnes per year of ethane, 1.51 million tpy of LPG and 0.86 million tpy of NGL.

This project is characterised by huge dimensions and big numbers, where any alternative solution in terms of plot space, energy consumption or weight reduction has the potential to translate into an enormous positive impact on the overall capital investment and also the operational costs of this project. The new owner has taken this opportunity to search for such alternative solutions with regards to the shell and tube heat exchangers of the Bid Boland gas treating plant.

Big numbers, big challenges It is clear that the project is characterised by its size. Specifically, that means a lot of engineering, plot space, transportation, construction, materials, energy consumption and maintenance. The plant consists of four trains, each train responsible for processing the sour and sweet gases into sweet gas, ethane, LPG and NGLs. Zooming in on the shell and tube heat exchangers, the original

Image 1: The inlet gas coolers, based on the datasheet design (left) and new design (right).

Table 1

Table 2

Treated Gas Cooler Conventional Alternative TEMA type CEU CFU Tube length (mm) 7,315 9,500 Shell ID (mm) 1,450 1,430 Weight each shell (kg) 36,192 46,758 Shells per unit 4 2 Total weight 4 trains (kg) 579,000 373,000 Shells required 4 trains 16 8

Inlet Gas Cooler Conventional Alternative TEMA type CFT CFS Tube length (mm) 7,315 9,500 Shell ID (mm) 1,450 1,600v Weight each shell (kg) 65,127 81,400 Shells per unit 4 2 Total weight 4 trains (kg) 1,042,000 651,000 Shells required 4 trains 16 8

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Annual 2016

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Table 3

Gas Heater Conventional Alternative TEMA type BEM BEM Tube length (mm) 1,929 1,929 Shell ID (mm) 930 930 Weight each shell (kg) 20,800 15,100 Shells per train 1 1 Total weight 4 trains (kg) 83,400 60,400 Shells required 4 trains 4 4

design consisted of four treated gas coolers, four inlet gas coolers and one gas heater per train. The three heat exchangers are needed for the treated gas cooler (cooling gas after treatment), the inlet gas cooler (cooling gas before it enters the next phase), and at a later stage, the gas heater (for heating the gas before entering the condensate drum).

Altogether, these 36 heat exchangers had a combined weight of 1,704,400 kg. They also required a substantial amount of plot space, not to mention energy consumption, the cost of the materials needed to fabricate them, installation and spares for maintenance, the costs of transportation and the impact on the environment.

Design on a diet Because of the scope of this project, alternative solutions can have an enormous effect.

Luckily, the new owner was very interested in alternative solutions and decided to grant Bronswerk (BHT) a chance to re-evaluate its plans for heat exchangers. BHT has a proven track record in the thermal and mechanical design and its engineers are trained to optimise the design, taking the overall process into consideration. That includes taking care of all client requirements regarding process design, thermal design, mechanical design, overall project execution steps, material handling and maintenance.

For the treated gas coolers and the inlet gas coolers, the company’s engineers immediately saw ways to reduce the number of shells.

Starting from scratch, they re-considered operating criteria such as the most convenient solution regarding pressure drop, the Logarithmic Mean Temperature Difference (LMTD) and an optimal heat transfer coefficient.

They were thus able to optimise the design of the treated gas cooler and the inlet gas cooler significantly. The number of shells was reduced to just two exchangers per train – and 50% of these could also achieve a weight saving of more than 35%. It was also achieved with a vibration-free design which could be handled on site. The new design saw a total weight reduction of 600,000 kg, greatly reducing plant costs, operational costs and required plot space.

Although the weight of each item in the process increased, the overall number of items decreased. The design also used less steel, meaning a 50% reduction in crane and handling cost, a 40% reduction in transportation, 50% fewer piping connections and all in all, considerably less capital investment.

See image 1 for comparison between the conventional design (two heat exchangers) and the improved design (one heat exchanger). Table 1 and 2 indicate the differences between the conventional and improved designs for the treated gas coolers and inlet gas coolers.

Heat improvements For the gas heater design no significant savings in the thermal design could be achieved. However, it was possible to optimise the design by changing the nozzle locations.

Instead of radial nozzles, axial nozzles were used, reducing the overall plot space and weight of the channels.

In addition, all welding was eliminated by the use of a forged channel (see image 2).

The benefits are less material and no welding – meaning no welding documentation was required and a minimal Non Destructive Examination (NDE) was needed. For NEWSBASE

Bronswerk, the lead-time was reduced significantly and risks during project execution minimised. Most importantly, this solution has resulted in significant client benefits like greater integrity (owing to the weld-less design, less plot space and reduced overall weight. These heat exchangers are all vibration free and have a complete thermal guarantee.

Table 3 shows a comparison between the conventional and alternative designs.

Less is more With the Iranian market opened up again, many more projects are being revived. That creates a lot of opportunities for both plant owners and operation managers – who might now be able to afford another look at the cost of ownership of the plant, in terms of energy consumption and maintenance, and the capital investment for material and plot space.

Bronswerk is keen to take up such challenges, and the above case study highlights the results that can be achieved.

In this particular scenario, the number and – more importantly – the total weight and plot space have been reduced dramatically.

Especially in the case of the inlet gas cooler and the treated gas cooler, these changes will have an impact on the total layout of the plant, reducing the necessary heat exchangers per train from four to just two, resulting in a reduction of installation and operational costs. Meanwhile, the gas heater also benefits from greater higher integrity as a result of the weldless design.

Smarter design directly translates into advantages for both the plant owner and the plant manager.

Having been granted the chance to alter the cost and efficiency of this project radically, Bronswerk engineers are keen to be given more opportunities to do similar work in the future. n Contact: Femke Schaefer,

Marketing Manager Tel: +31 (33) 24 72 500 Email: femke@bronswerk.com Web: www.bronswerk.com

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InnovOil

2016 Annual

Island riserless coil tubing ready for heavy intervention

Island Offshore’s award-winning riserless technology is making the jump from light interventions to heavier operations.

Tim Skelton reports on the company’s plans for 2017

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aving successfully proved its riserless coil tubing technology on several test wells, Norwegian marine engineering specialist Island Offshore believes it is ready to extend the process, enabling it to perform heavy subsea intervention tasks at producing wells.

Instead of using a rigid marine riser attached to a fixed platform, Island Offshore’s design uses coiled tubing linking an open-water vessel to a subsea injector, with the waterproofed tube kept in tension by a second on-board injector. This provides flexibility and allows drilling to take place in remote locations where little or no infrastructure exists. Pressurised fluid inside the coil tube drives a hydraulic mud motor that rotates the drill bit, while the subsea injector places weight on the bit to move it into the well.

Riserless drilling offers several key advantages. From a safety perspective, if a blowout or another well-control operation occurs the surface vessel can move away from the drilling site at short notice, while at the same time keeping the tubing in contact with the well, allowing mud to be pumped in to hold back a blowout. The risk of injury to personnel is also reduced.

Riserless operations also result in reduced impact on the surrounding environment, as less equipment is required and less time is spent at the well site compared to a full drilling rig. Moreover, savings on manpower and lower capital expenditure make operations far cheaper.

Heavy going The technology was first tested in 2014 before making the jump to the the oil and gas sector in 2015. Working with Centrica, Island used coiled tubing drilling linked to its Island Constructor mobile wellintervention vessel to drill a pilot hole to check for shallow gas at the former’s Butch field in the Norwegian North Sea. Centrica said the operation had saved it “about 30 to 50%” in costs.

In August this year the success of the test led to the two companies jointly receiving the Innovation Award at the Offshore Northern Seas (ONS) conference in Stavanger.

According to Island, all the advantages demonstrated in the test will apply equally when the riserless coiled tubing technology is adapted for heavy subsea interventions.

Coiled tubing on the Island Constructor NEWSBASE

The company says it will allow operators to perform heavy maintenance to increase production and reservoir recovery rates using less equipment and fewer personnel.

Such maintenance could involve, among other things, the removal of sand, scale and other blockages to restore the original inner dimensions of production tubing, and general plug and abandonment (P&A) operations.

Using coiled tubing for such work today requires a fixed drilling rig and a complex workover riser system, and this is rarely done owing to the high costs and safety challenges involved. Island says it can make these operations cheaper and more reliable by running the tubing through open water without a riser, and using similar methodology as the currently most popular method for interventions: Light Well Intervention vessels running a wireline through a subsea lubricator.

To make this suitable for coiled tubing, a subsea injector controlled and powered by a remotely operated vehicle (ROV) will be installed on top of the subsea lubricator.

Island has already built the innovative injector and is now adding a stripper element between this and the subsea lubricator in order to hold back pressure from the well. Once this is qualified for offshore use, it says it will be ready to offer the technology to the market for heavy interventions in subsea wells. This is expected to happen by the second half of 2017.

In a recent company press release, Island Offshore manager for top-hole drilling and P&A activities Per Buset sounded upbeat about the technology’s prospects. “Oil companies rarely do heavy well intervention because of the high costs, but they have [often said] that if the cost is low enough they will do it. This will be a game-changer for intervention work in subsea producing wells, including the plug and abandonment market,” he said. “The potential for both oil companies and service providers is huge.” n

Annual 2016

InnovOil

Subsea Integration signed up for Dalmatian work

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Subsea 7 lays a flowline at Dalmatian South

Murphy Oil contract will see the Alliance partnership design and install the industry’s longest subsea multiphase boosting tieback

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espite tough times – in many cases because of them – subsea developments are still pushing the innovative envelope. While more and more facilities are planned as subsea tiebacks, operating envelopes continue to be pushed, be it for compression at Norway’s Asgard, or depth and pressure tolerance at the Julia field in the Gulf of Mexico.

Meanwhile, business models such as that of the Subsea Integration Alliance have also come into their own. Earlier in December, the partnership – a joint enterprise between OneSubsea, Schlumberger and Subsea 7 formed in 2015 – announced that it had been awarded the industry’s first deepwater integrated subsea engineering, procurement, construction, installation and commissioning (EPCIC) contract for multiphase boosting system. The firms will work to design, build and install the system for Murphy Exploration & Production Company USA – a subsidiary of Murphy Oil – at its Dalmatian field in the Gulf of Mexico.

At 35km, the project is pegged to be the industry’s longest deepwater subsea multiphase boosting tieback. The contract includes topside and subsea controls, as well as an integrated power and control umbilical along its length.

The Dalmatian field lies across De Soto Canyon Blocks 4, 48 and 134, in water depths of between 5,900 feet (1,800 m) in the North Field and 6,400 feet (1,950 m) in the South. It produces oil, gas and NGLs and is currently tied back to the Petronius

compliant tower operated by Chevron and Marathon Oil. Installation is scheduled to begin in 2018.

In a statement, OneSubsea and Schlumberger president Mike Garding said: “This subsea boosting technology will improve Murphy E&P’s ultimate recovery through a cost-effective, record tieback. The innovative business model of the alliance further contributes to greater certainty of cost and return on investment.”

Subsea 7’s chief executive officer, Jean Cahuzac, added: “This contract recognises our successful alliance model that brings together Subsea 7’s SURF technology and extensive track record in the delivery of large-scale complex EPCIC projects, with OneSubsea’s reservoir and subsea production and processing systems technologies. Our alliance presents Murphy E&P with many opportunities to improve their field economics, and reduces complexity, cost and risk to achieve production objectives safely, on time and NEWSBASE

within challenging cost targets.”

The value of the contract has not yet been released. InnovOil has reached out to Schlumberger for more information.

Records on a roll The project has already achieved some notable records. In 2014, Subsea 7 was awarded the contract for the Dalmatian South flowline. At 1,950m, it is the deepest reeled pipe-in-pipe installed by the company to date.

The pipe-in-pipe flowline system itself was comprised of 10-inch x 18.3mm WT X65 outer sleeve pipe and 6-inch x 15.9mm X70 inner pipe, with associated water stops, centralisers, buckle arrestors and bulkhead connections. Pipe welding, including procedure qualification, was executed using Subsea 7’s automatic welding system. The project was completed in December 2015. n Contact: Susan Ganz - Schlumberger Email: Sganz1@slb.com Web: www.slb.com

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InnovOil

On the radar

2016 Annual

What caught our attention outside the world of oil and gas this month

Silly putty makes smart sensors The applications for graphene know no bounds. Researchers at Advanced Materials and BioEngineering Research (AMBER), a research centre in Trinity College Dublin (TCD), have added the material to novelty children’s material silly putty® (polysilicone), allowing it to conduct electricity. The result is the ability to create “extremely sensitive” sensors.

The results, published this month in the Science journal, could be used to create inexpensive devices and diagnostics in a number of technology sectors

The paper was produced by Professor Jonathan Coleman from TCD and in collaboration with Professor Robert Young of the University of Manchester. Working with postdoctoral researcher Conor Boland, the team found that the putty-graphene mixture was very sensitive to deformation or impact. When placed onto the chest and neck of human subjects it could be used it to measure breathing, pulse and even blood pressure.

For more mechanical applications, it proved to be “hundreds of times” more sensitive than conventional sensors with regards to strain and pressure, and as an impact sensor. So much so, it could be used to detect the footsteps of small spiders.

Coleman stated: “What we are excited about is the unexpected behaviour we found when we added graphene to the polymer, a cross-linked polysilicone… While a common application has been to add graphene to plastics in order to improve the electrical, mechanical, thermal or barrier properties, the resultant composites have generally performed as expected without any great surprises. The behaviour we found with G-putty has not been found in any other composite material. This unique discovery will open up major possibilities in sensor manufacturing worldwide.” n

Silly putty mixed with graphene also has the entertaining property of being magnetic NEWSBASE

Yes, we scan While most ports handle thousands of containers a day, only a handful can be inspected by human security for illicit contents (such as weapons), and that process may take up to 10 minutes per container.

Instead, a group of researchers at University College London (UCL) is working together with US firm Rapiscan to develop a faster inspection method using a combination of x-ray scanning and artificial intelligence.

Thomas Rogers, one of the UCL team, reckons that its machine could take just 3.5 seconds per container.

Its so-called Threat Image Protection (TIP) techniques were created by showing the system thousands of scanned container images, which had been altered by the team to include common metallic objects which may be concealed in real containers.

In a paper published in August, the team’s results showed that the system recognised nine out of ten objects, with a false positive rate of only 6% – a rate which has now dropped to 0.5%, the group told The Economist.

The team now hopes to use the system on real containers and with illegal objects deliberately concealed. Should it work, the project leader, Dr Lewis Griffin, has said that the artificial intelligence technology could be included in Rapiscan systems in the next few months.

Beyond ports, the technology could also be employed in airport security to optimise the screening of passengers’ bags. n

Annual 2016

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Boeing acquires Liquid Robotics Aerospace giant Boeing is to acquire autonomous marine technology developer Liquid Robotics.

In particular, Boeing is looking to capitalise on innovation such as the company’s Wave Glider ocean surface robot – reportedly the world’s first solar and wave powered ASV – to grow its “seabed-tospace” autonomous capabilities.

The terms of the agreement were not disclosed.

The acquisition follows a period of cooperation which began in 2014 and saw the two companies develop the Sensor Hosting Autonomous Remote Craft (SHARC®), a version of the Wave Glider. The SHARC, integrated with Boeing’s advanced sensors, connects intelligence, surveillance and reconnaissance capabilities ranging from satellites to manned and unmanned aircraft to sub-surface crafts.

“With Liquid Robotics’ innovative technology and Boeing’s leading intelligence, surveillance and reconnaissance solutions, we are helping our customers address maritime challenges in ways that make existing platforms smarter, missions safer and operations more efficient,” said Leanne Caret, president and CEO of Boeing Defense, Space & Security. n

Microspines key to climbing robots Roboticists at Stanford Jet Propulsion Laboratory have combined two in-house technologies as part of efforts to develop a cliff-climbing robot.

Drawing on spines created for the aptly named Spinybot, the team adapted the technology for use with a larger system, RoboSimian, the goal being to allow the dextrous robot to grip rough rock surfaces.

Based on insect tarsal spines, each one can sustain loads mostly parallel to the surface but also up to 20° outward from a surface.

The team then made larger 15-mm spines – about the size of a US quarter dollar coin – assembled together in tiles on RoboSimian’s hands, and

supported by an internal spring to ensure pressure against a contact surface. These mechanisms sit in 3D printed sleeves, each of which will hold around 60 spines.

In practice, these can help increase friction coefficients by up to three times. The researchers tested the spiny palm on nine different surfaces and reported up to 710 N of shear adhesion.

In later tests, a 100mm by 120mm block of 12 spiny tiles was able to support a 60kg shear load on a rough concrete surface.

Depending on the surface, the technology could be used to enable better robots for hull inspections, or on robots needed to traverse the surface of asteroids or other planets. n NEWSBASE

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InnovOil

New drillship launched with Gusto

2016 Annual

The new design targets efficiency and cost reduction for future deepwater operations

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ore than most of the industry’s sub-sectors, the deepwater drilling market in particular has had a tough year. With costs slashed, few operators are in a position to embark on the expensive and technically challenging developments which were being talked up a few years ago.

Nevertheless, day rates for deepwater drillships are still hovering at around US$475,000 – a figure that would benefit from being reduced through some clever innovation and smart engineering.

Operators and technology providers are already concentrating on doing more with less, as efficiency remains the watchword. As a result, many new rigs have been slimmed down or totally redesigned with specific markets and tasks in mind. In October, for example, Aker Solutions unveiled its new “Lean Semi” semi-sub design, with a view towards meeting the greatest demands of the widest market – and doing so more affordably.

The same can be said of drillships. Dutch engineering and design firm GustoMSC recently announced a new design, with a view to bringing mid- to deepwater developments online in as cost-effective a manner as possible. Ditching the overspecification of ultra-deepwater vessels, GustoMSC has dispensed with superfluous equipment and focused on meeting the broadest drilling requirements with optimised hardware.

This the central focus of the Scylax. The

company notes: “Whereas ultra-deepwater units feature ever-increasing hook loads and capacities, these requirements can be reduced for a large amount of the wells in [the] deepwater. Designing the Scylax based on these rationalised requirements allows for different choices to be made in the design, reducing building and operating costs.”

Scy is the limit GustoMSC is keen to emphasise that the Scylax is “smarter, rather than just bigger or heavier.”

In its basic form, the Scylax is a 190m vessel with a displacement of 53,000 tonnes and accommodation for up to 160 personnel. Its design features a single derrick or drilling mast set-up with offline stand building, dual BOPs and is aimed at operations in water depth ranging from 7,000-10,000 feet (2,100-3,000m).

The designers note that the vessel’s single well centre can service most well designs, while using less equipment. In turn, that reduces the overall build cost and the costs of maintaining and operating the drill floor – all of which should save operators money.

Hook load and set-back capacity – 2,000 kips and 1,000 tonnes respectively – are also based on common deepwater well designs, rather than the bespoke arrangements of the more specialised ultra-deep units.

All major manufacturers’ drilling packages can also be integrated into the design, which can drill distances of up to 30,000 feet (9,100m). Similarly, the NEWSBASE

dual-BOP carrying capacity – completely superfluous or completely necessary, depending on one’s point of view – can reduce downtime in the event of any disruption. In addition, managed pressure drilling systems can be included in the design, or provisions can be made in case systems are added at a later date.

As has been seen with recent rig design, deck flexibility is also important if new vessels are to meet a broader array of missions than before. The Scylax has 2,900 m2 of dedicated deck area, with almost the same again (2,100 m2) free for other equipment as needed, and a further 600 m2 of storage, for a total of 5,900 m2 – an area GustoMSC claims is the largest in its class.

That is supported by in-hull riser storage, in-hull mud and bulk systems and protected walkways.

Its total thruster power of 24 MW means transit speed is a fairly brisk 13 knots, making the Scylax ideal as a fast response to short campaigns. This also helps to reduce transit periods, again saving money.

With day rates so low already, new rig designs must distinguish themselves in terms of cost reductions and efficiency gains – GustoMSC is confident that it can do so.

Speaking at the unveiling of the design at OSEA 2016 in Singapore, the company’s marketing manager, Mattijs Faber, commented: “Research tells us that Skylax will be effective in 94% of wells globally, and is particularly suited to wells in this region.

It is very focused, half the size of what you

Annual 2016

InnovOil

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The Scyllax drillship

2017 will see new opportunities for us to add value to our clients and help them distinguish their operations from the rest of the market,” he added.

The unveiling of the design is also a sign that things may be looking up for drillers in 2017. A US$50 oil floor suggested by the latest OPEC meeting is not the turnaround some will have been praying for, but it offers a lifeline to the beleaguered deepwater market – a lifeline that may well be attached to vessels like the Scylax. n can find in the market, and is therefore considerably cheaper than ultra-deepwater units.”

“The Asia-Pacific is a very important

market for us, and OSEA, being held in Singapore, where many rig owners have a foothold and many shipyards are located, makes it a vital hub for us… I am confident

NEWSBASE

Contact: Tessa Vleugels Tel: +31 10 2883 000 Email: tessa.vleugels@gustomsc.com Web: www.gustomsc.com

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InnovOil

Annual 2016

2017: Global outlook

NewsBase editors look at the technology and projects which have shaped the industry this year, and consider what is on the horizon in 2017

Africa One potentially interesting development is Trends established in 2015 continued in transferring technologies into new regions into 2016, with spending plans falling and in the deepwater. Anadarko Petroleum carried companies delaying big spending plans out appraisal work offshore Cote d’Ivoire at its around Africa. The deceleration manifested Paon (6) find, with an apparently successful largely through capital expenditure cuts, move into horizontal drilling. The move may a worldwide feature exacerbated by provide additional productivity in the offshore, concerns over regulatory risk and mounting but the economics are not yet clear. government debt in a number of African locales.

Ed Reed, AfrOil Editor Governments have taken some steps to attract new interest, showing increased flexibility on licence terms and launching licence terms. Spending on seismic showed some interesting signs, driven by substantially lower pricing, but drilling was in painfully short supply and offshore rig deployment fell to 12l 7 near-record lows.

8l l 11 While companies seem l14 2l l 9l content to run existing facilities, l10 and continue spending on l13 existing plans, the pre-FID pipeline has largely seized up.

Royal Dutch Shell’s decision l5 to delay approval for its Bonga South West (1) development highlighted the problems for 6l l1 l4 l3 major project spending in Africa.

Some signs of life, though, have been seen in gas production plans. Eni approved its major Zohr (2) plan, in February, targeting a start of the end of 2017, while BP also made additional commitments in Egypt. Gas output in the country will largely go to the domestic market, which has benefited from government action on pricing, and there have also been some positive signs about restarting LNG plants.

Most significantly, though, was the Sanctions on Iran (7) were finally lifted in continued move towards the mainstream January 2016, six months after a deal was of floating LNG (FLNG). Eni is nearing FID on agreed with the UN P5+1. For all the softening its Coral South (3) plans, off Mozambique, of rhetoric and signals of intent from IOCs, with BP having committed to offtaking gas though, certain US sanctions remain in from the project. Given the preponderance place and have slowed the expected foreign of major offshore gas finds, FLNG appears to investment flows. Nevertheless, Iran’s be a natural fit for the continent. After some production profile has changed dramatically havering, Schlumberger agreed to work on over the past year: output has increased from Ophir Energy’s Fortuna project (4) in Equatorial 2.8 million bpd in December 2015 to 3.67 million Guinea, alongside Golar LNG, and Kosmos bpd in October this year, on the back of a wider Energy has talked up FLNG for its Greater market for crude from the Islamic Republic.

Tortue (5) development in Mauritania-Senegal.

Neighbouring Iraq (8) has had a mixed year.

Middle East

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The government has struggled financially, being unable to fund the rapid development of its massive oil reserves, as it has pushed back Daesh militants and begun the fight to retake the city of Mosul. The appointment of Jabbar al-Luaibi as Oil Minister in the autumn brought new optimism, though this has now subsided somewhat, following a bid round which was launched, then unceremoniously dropped in the fourth quarter.

In the Kurdish north, relative calm appears to have broken out, with an ‘understanding’ between Baghdad and Erbil regarding oil production and export. However, the Kurdish Regional Government (KRG) has had its share of money troubles, falling short of expected payments to IOCs developing its resources.

Hydrocarbons behemoth Saudi Arabia (9) had a somewhat quieter year than the one before, making incremental output gains with new drilling programmes at fields including Ghawar, Khurais and Shaybah.

Externally, Riyadh’s (and OPEC’s) agreement in late November to cut production by 1.2 million bpd finally brought about an uptick in oil prices, but this was limited by the market still being oversupplied.

Oman (10) has made steady progress with its headline Khazzan and Mukhaizna projects, with the former expected to produce first gas on schedule – in 2017 – providing feedstock for a new refinery and petrochemical complex at Duqm on the Al-Wusta coast.

In the Eastern Mediterranean, Israel (11) has launched a new bidding round, whilst in neighbouring Lebanon the appointment of a new government is seen as providing the stability required to press on with its own offshore auction.

Syria (12) and Yemen (13) remain torn by war, and energy sector efforts are far outweighed by those being made to conclude the ongoing sectarian violence.

Finally, Bahrain (14) has made a surprise return to the upstream radar, appointing Italy’s Eni to assess its resource potential.

Ian Simm, MEOG Editor

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North America Across North America, efforts to cut costs continue to be the greatest shapers of exploration, production and technology.

Shale drilling has not lost the ability to surprise the industry with its resilience.

Through a combination of high-grading, costcutting and the trialling of new techniques, shale drillers have set new records and pushed the boundaries of what was considered possible even a year or two ago. This has included record volumes of proppant employed in frack jobs (Chesapeake (1) used 25,000 tonnes of sand in a Louisiana well) and horizontal laterals being drilled to new lengths (an 18,500-foot [5,600m] lateral drilled by Halliburton and Eclipse Resources). We can expect these records to be broken again next year as drillers continue to experiment.

As breakeven prices keep falling and some drillers at least prepare to bring more rigs on line, further technical innovations can be expected. Services providers are also stepping up their efforts here. Schlumberger is currently trialling two prototypes of its “rig of the future” in the Permian Basin, with a view to releasing the final model in 2017.

While high-grading remains a major

strategy, some shale drillers are moving into more difficult areas. For instance, Apache has been talking up its Alpine High (2) discovery in the Permian Basin, though there have been warnings that the find is located in a particularly geologically challenging area, where results have previously been poor. How Apache performs remains to be seen, but a shift away from high-grading towards less productive areas will be inevitable in the coming years, as the sweet spots are tapped.

While the majority of drillers – both independents and super-majors – have been focusing on shale plays, where production can be easily scaled up or down depending on oil prices, some developments have been seen offshore as well.

Notable deepwater projects to come on line this year include Shell’s Stones (3) and ExxonMobil’s Julia (4) – both Lower Tertiary projects. Stones was notable for several innovations, including the use of 3D printing to create a prototype of the system involved – something that could become more commonplace among offshore operators in the coming years as they design increasingly complex systems.

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Another offshore operator of note in the US Gulf of Mexico is BP, which this year rolled out a water injection project at its Thunder Horse (5) platform to extend the field’s life.

BP anticipates this will help it to recover an additional 65 million boe.

The company has also just sanctioned its Mad Dog Phase 2 development, having managed to slash the cost of the project from an initial US$20 billion to an estimated US$9 billion. The company sees potential for a bright future in the Gulf thanks to such projects, a focus on cost-cutting, standardisation and simplification.

In Canada, the Fort Hills oil sands project (6) and the offshore Hebron (7) project are due to start up in 2017. While final investment decisions (FIDs) on megaprojects have been rare recently, a strong performance by these new projects could help revive appetite, as well as illustrate the latest technological advances.

Shale will continue to dominate the North American landscape in 2017, but what few new oil sands and offshore developments there are will show that technological advances are still being pursued across the board.

Anna Kachkova, NorthAm Editor

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Annual 2016

Latin America As predicted in our last annual review, 2016 proved to be a year of mixed fortunes for Latin America. Weak oil prices continued to weigh heavily on E&P spending. But the move away from populist leftist governments to more conservative administrations, most notably in Brazil and Argentina, is positive for inward investment in the region.

Argentina’s new government under President Mauricio Macri has made great strides forward in the energy sector. Subsidies have been unwound and the administration is pushing producers hard to increase oil and gas output so expensive imports can be pared back. Macri has made ending LNG imports a goal by the end of the decade.

In order for this aim to be achieved, output will have to ramp up rapidly from the Vaca Muerta (1) shale and other unconventional plays across the country.

Shale drilling costs are falling rapidly in Argentina. It currently costs US$9.5 million to drill a well in the play, down from US$10 million at the start of the year and heading closer to the US$7 million mark Macri’s team have targeted. Costs are coming down as experienced shale developers like ExxonMobil advance projects with YPF and as infrastructure improves. The government is investing heavily in enhancing local road and rail infrastructure to ease the flow of proppant and frac sand into the Vaca Muerta.

Mexico’s (2) energy reforms are starting to bear fruit, with the country’s first ever deepwater auction in December attracting a roster of the biggest names in the global oil industry. BHP Billiton, BP, CNOOC, ExxonMobil, Petronas , Pemex, Statoil and Total were all on the list. The country’s oil output has fallen below 2 million bpd this year, but it is likely to start rebounding over the next five years as the acreage sold to private companies in early bid rounds becomes more productive, and then further in the future when the coveted deepwater blocks come on stream. Production of over 3 million bpd is probable in a decade.

Brazil (3) has been the biggest story of 2016 in Latin America. The oil price collapse and the Car Wash scandal forced out the government of impeached ex-president Dilma Rouseff. A new, more business-friendly administration under President Michel Temer has taken office and, with new Petrobras president Pedro Parente, has sought to reframe the dysfunctional oil and gas industry.

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New laws governing the pre-salt that remove the obligation for Petrobras to be the operator of all blocks and also ease national content rules are likely to have a positive effect on development. Statoil has already taken advantage of the situation, growing its presence in the pre-salt, and others are likely to follow with the first auction of presalt blocks lined up for 2017.

Venezuela (4) continues to be a basket case.

The economy continues to tank, though the discredited government of President Nicolas Maduro still clings on to power. Next year could see the country cross the Rubicon, however, as a default is highly likely. A strong and sustained rise in oil prices appears to be the country’s only hope, but even that might not be enough, given the mess the economy is in.

Ecuador (5) has also had a difficult 12 months on the back of weak prices. But progress has been made in developing the Ishpingo Tambococha Tiputini (ITT) project. In September the Tiputini field began pumping at a rate of 20,000 bpd, which was above government expectations. Output could rise to 50,000 bpd in 2017.

The project is critical to Ecuador’s future, given that it sits on an estimated 1.7 billion barrels of reserves. Development of ITT is

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forecast to require about US$4 billion in total investment. Spending at Tiputini alone is estimated at around US$1.5 billion between 2014 and 2018.

Finally, Peru (6) had some positive news in late November when China’s state-run CNPC reported the discovery of an estimated 4 tcf (110 bcm) of gas spread across four structures in Block 58 at a depth of 4,000-5,000 metres. The find would add around 30% to Peru’s total gas reserves and, with the new government of President Pedro Pablo Kuczynski looking to attract greater foreign direct investment, could herald a brighter future for the county’s hydrocarbons sector.

Ryan Stevenson, LatAmOil Editor

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Europe The North Sea (1) has endured a torrid couple of years since oil prices crashed. OPEC’s plan to cut production in late November looks to have put a floor under US$50 per barrel oil, but even that means that margins remain tight for operators in the high-cost region.

This has led many of the big guns to review their operations, with Royal Dutch Shell and ExxonMobil reportedly considering multibillion dollar sales of their assets in Norway.

BP and Det norske oljeselskap merged their assets in Norway to create Aker BP. It now operates as one organisation and has considerable ambitions on the Norwegian Continental Shelf (NCS).

The exit of the majors has created an opportunity for smaller, private-equity backed independents, like Siccar Point Energy. The company, which is backed by Blackstone, the US private equity group, and GIC, the Singaporean sovereign wealth fund, recently agreed to pay US$1 billion for the UK business of Austria’s OMV in a deal that will make it a partner of oil majors BP, Statoil and Chevron in some of the biggest remaining North Sea fields.

Otherwise the tale of the North Sea in 2016 has been one of cost cutting, integration and closer collaboration. It

has been a painful process but means the industry, and oilfield service providers, will emerge stronger and leaner when the projected uptick in business occurs.

The Eastern Mediterranean continues to be a dynamic area. A flurry of exploration activity is anticipated in 2017, with companies searching for more gas to advance critical infrastructure projects like pipelines and LNG plants. Eni and Total are due to drill off Cyprus (2) next year, while Lebanon is reviving a bid round and Israel is due to award more blocks.

Ryan Stevenson, EurOil Editor

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Annual 2016

Russia & Central Asia Western sanctions targeting the use of advanced technologies in Russia’s oil industry have failed to check production growth, with output hitting a new post-Soviet record of 11.23 million bpd in November.

Some of this growth has come from challenging new projects in Yamalo-Nenets, including Gazprom Neft’s Novoportovskoye field (1), which is expected to deliver 50,000 bpd this year, up from a meagre 5,800 bpd in 2015.

A further rise in output will be possible thanks to the launch of six Arc7 Icebreakers that ensure year-round delivery of the field’s crude to market.

More recently, Gazprom Neft and Rosneft started commercial operations at East-Messoyakhskoye (2), Russia’s northernmost oilfield. The field – which was discovered in the 1980s but was shelved until now because of inadequate technology – came on stream in September. It is slated to produce around 110,000 bpd of oil by the end of the decade.

At the same time, Russia has also been able to sustain output at more mature assets with the help of enhanced oil recovery (EOR). For instance, mid-sized producer Bashneft (3) saw extraction at its brownfield sites in the Volga-Urals region rise by 0.5% in the January-September period to around 250,000 bpd.

Even so, sanctions that bar Russian oil producers from accessing sophisticated western technology have claimed some casualties.

Despite Rosneft and ExxonMobil’s discovery of 750 million barrels at Pobeda (4) in September 2014, offshore drilling in Russia’s Arctic has ground to a halt.

Moscow does not expect to bring any new Arctic projects on line before 2035 and has even declared a temporary moratorium on the award of new licences.

Still, Gazprom Neft’s Prirazlomnoye field (5) stands as a testament to the region’s potential. The field is scheduled to deliver 42,000 bpd of oil in 2016 and around 100,000 bpd in 2017, up from 17,500 bpd last year.

Sanctions have also complicated Russia’s efforts to tap its unconventional oil and gas reserves. Without foreign assistance, many Russian producers appear disinterested in exploring for these resources.

The one exception is Gazprom Neft, which has been making increasingly extensive use of hydraulic fracturing and horizontal drilling this year. In October, it announced it had completed a 30-stage fracking operation at a field situated in the Bazhenov basin (6).

Even so, the company has slashed its production targets for the site and NewsBase believes tight oil will remain low on Russia’s list of priorities.

Meanwhile, in Kazakhstan, the massive Kashagan (7) offshore field was relaunched in October after years of delays.

The field, which contains 9-13 billion barrels of oil, is expected to produce 230,000 bpd by 2018. Production will rise even further from the plateau if the field’s partners can agree on a second development stage.

In the summer, Chevron and its partners at the onshore Tengiz oilfield (8) also signed off on a US$37 billion expansion that will raise oil output at the site by around 260,000 bpd. This will bring total production up to about 1 million boepd.

Joe Murphy, FSUOGM Editor

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Asia/Pacific Low oil prices drove a lot of money out of the Asian upstream this year, leaving very little funding for high-tech developments.

After years of defying expectations of an imminent crude output decline, China’s majors finally bowed to production economics this year, choosing either to close older marginal fields or to curtail enhanced oil recovery (EOR) programmes at mature giants. This behaviour is likely to continue throughout 2017 as the NOCs move to conserve cash for other, high value-adding projects at home or abroad. They will also be watching how Beijing’s efforts to introduce greater private sector spending in oil and gas production unfold and affect their own assets.

One area of the Chinese upstream likely to see continued spending is the unconventional gas sector. The central government has grand plans for shale gas, targeting production of 30 bcm per year by 2020 and 80-100 bcm by 2030. While the country is anticipated to surpass its target of 6.5 bcm this year, it still has a long way to go before its 2020 and 2030 targets are within reach.

Further drilling and development throughout the prolific Sichuan Basin (9) should be expected next year, with Sinopec focused on its Fuling block and PetroChina on Changning-Weiyua. Sinopec is also set to develop a new block in Wulong in partnership local government-owned Chongqing Xianglong and work will likely begin next year given that it has already been explored.

Elsewhere in Asia the story is very much about the adoption of floating liquefaction or regasification capacity over more costly onshore projects.

The former is fast becoming a preferred alternative in the wake of the painful lessons learned in the Australian sector in recent years, with several world-class developments there experiencing cost blowouts and delays. This shift has not necessarily been welcomed by everybody, though, with some governments worried about missing out on the greater local economic development associated with onshore facilities. Indeed, Indonesia (10) has pushed Inpex and Shell to commit to an onshore facility after the pair originally planned to use a floating plant. As such, the scale of the project may need to be ramped up nearly fourfold to make it economically viable.

Floating storage and regasification units (FSRUs), meanwhile, offer Asia’s less developed economies a quicker and significantly cheaper alternative to onshore installations for tapping into the global gas supply market. This is set to continue, with Pakistan (11) already lined up to launch a second FSRU in June 2017.

In the downstream, a new wave of investment decisions should be expected in the coming year, continuing a trend towards capacity upgrades seen this year. China’s emergence as a major fuel exporter, in part thanks to crude import reforms concerning independent refiners, has several regional downstream hubs nervous and refiners at these will be looking to ensure they remain competitive in the years to come. Vietnam (12) has already been caught out; free trade agreements (FTAs) signed with ASEAN and South Korea (13) are undermining the effectiveness of its own downstream, leading to several developments being cancelled.

Andrew Kemp, AsianOil & ChinaOil Editor

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a DNV GL company

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December 2016

November 2016

Stack image

October 2016

Box clever

Flare monitoring from LumaSense

Gas Techno’s Mini GTL Page 6

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Semi, Skimmed

Aker Solution’s Lean Semi™ design

EARS TO THE GROUND

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The latest in seismic and geophysics

SHaPe oF SHIPS To CoMe

rolls-royce talks autonomous and remote vessels

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ETHANOL GOOD THINGS ORNL catalyst turns CO2 to fuel

Silver liningS

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Swagelining polymers fight corrosion

MEDICAL MARVELS

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The tech transfer transforming reservoir analysis

Take your Peek Portable 3D printing

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September 2016

Captaur the flag

July 2016

OiL yOu can eat

How the seacaptaur system could unlock the world’s small pools

p&A solutions, collaboration and more Page 15

How oildegrading bacteria help spill response

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June 2016

Decom Developments eye on bAtteries

Hotter batteries could power downhole equipment Page 26

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Rock on

The team behind 3-D printed “smart” rocks Page 12

BReaking BonDs

Optimise prime The latest production optimisation strategies

The chemicals and fluids revolutionising the oilfield Page 17

EElumE-inating thE dEpths

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Learning tO FLi Well-SENSE’s intervention revolution

norway’s subsea snake rovs Page 9

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QUestIonIng IntegrIty

April 2016

February 2016

BlUE-SEA thinking

Behind PTTEP’s home-grown AUV Page 20

A look at asset integrity solutions Pages 13-21

AU-VIPs

New research on AUV missions Page 6

BlItzkrIeg on BoPs GE and Diamond make an new partnership

SUBSEA Expo 2016

SubseaUK’s Neil Gordon looks at the year ahead Page 12

crAcking thE cASE

New research could revolutionise hydrogen production Page 7

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The year in review

Technologies which transformed our 12 months

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InnovOil

2016 Annual

THE BEST OF 2016

Pretty FLI for a fibre line

Andrew Dykes sat down with Well-SENSE Technology founder Dan Purkis to discuss FLI – an entirely new and disruptive approach to well intervention

B

resistant etc., and all that means the designs uilding equipment that can become very complicated and take a long survive downhole is hard. Dan time to come to market,” he continues.

Purkis is quick to remind me that The solution, in Purkis’ words, is “a new “people think designing rockets discipline.” The Fibre Line Intervention (FLI) and spaceships is difficult, but that’s nothing concept is a range of dissolvable intervention compared to downhole tools!” Indeed, tools, deployed into the well on a single that simple truth alone adds years to fibre-optic cable, which could replace or development timelines, millions of dollars compliment thousands of intervention to budgets, and keeps service prices high. operations – from perforations Purkis thinks that needs to to pressure, temperature and end.

“One of the flow sensing – all performed His solution is to use huge problems faster and at a far lower cost disposable tools that do not need to withstand the at the moment than the industry is used to. downhole environment – at is the cost of Dissolving expectations least not for long. “One of the the current Purkis is no stranger to huge problems at the moment designing downhole tools. is the cost of the current solutions” Having worked at Petroleum solutions,” he explains by Dan Purkis Engineering Services (PES), phone from Aberdeen. “The a company which pioneered products and services that are some of the first intelligent completions, offered are too expensive for the current before being acquired by Halliburton, market. That represents a huge opportunity he went on to found Petrowell, where to try and solve the problems using he designed a suite of RFID-operated alternative technologies.” completion and drilling tools. After six years Engineers spend years designing rental in development the technology was sold tools that must have long term high to Weatherford. His latest venture, Welltemperature reliability whilst being both SENSE Technology, was formed in July 2015 serviceable and robust. It takes years to train with the aim of “bringing technology from engineers to be able to design to this level outside of the industry and redeploying it.” and it takes years to build, test and qualify Purkis believes that the sector’s risk adverse such tools. “A tool has to be really reliable, approach to innovation means it overlooks corrosion-resistant, pressure-resistant, heat NEWSBASE

solutions to problems which have already been explored by other industries.

His method when approaching new intervention tools was to ask: “What would Google or Apple do?” The answer, he posited, was unlikely to lie in the industry’s standard trio of coiled tubing, electric line or wireline, all of which have their own technical challenges, require large surface spooling equipment and multiple personnel to operate. Ultimately the tool designers end up with a downhole product that is a “20foot long steel rental tool; again.”

Disregarding the existing systems, he instead looked to the incredible strides made in consumer electronics and materials.

“No-one in the market at the moment makes disposable tools,” he says. “Because with current approach to design, it would be too expensive and you can’t leave a tool down the well.” So he set about making some.

Taking inspiration from out with the oil and gas industry, the most revolutionary aspect of FLI is its ability to be discarded.

With a housing based on a biodegradable polymer and water-soluble metal alloys, the tool is used and abandoned in the well, where it dissolves in a matter of days.

This tool is deployed into the well via a surface-connected fibre-optic line, allowing the FLI tool to “freefall into the well and be left there. You don’t get it back, and it doesn’t cause an obstruction.” One of the

Annual 2016

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THE BEST OF 2016 Far left: An early concept design for FLI Left: Dan Purkis, Well-SENsE Founder and Technology Director

footprint on the surface. While other systems require a truck-mounted spool of cable, 10,000 feet (3,000 metres) of fibreoptic takes up the same space as a can of baked beans. Mounted inside the FLI tool itself, it unspools as the tool free falls into the well, with a depth reading provided by a laser range finder. When the FLI tool has completed its job, the line is either cut – leaving the tool and fibre to disintegrate in the well – or alternatively the fibre optic can be recovered using a reel at the surface.

biggest risks in standard intervention jobs is becoming “stuck in hole” – but because FLI tools never need to be recovered, this risk never occurs, meaning no costly down time or fishing operations. “This would enable production optimisation operations to be performed on wells formerly deemed technically to risky or economically unviable,” Purkis says.

As its name suggests, the key component to FLI is a fibre-optic cable. Being strong and light – typically around 0.25mm in diameter – it is ideal for connecting small pieces of downhole equipment back to the surface. In

its bare format, it is also very cost effective, even at lengths of 4 to 6km, which is more than enough to reach the deepest sections of most wells. Moreover, it offers a revolution in data transfer speed. While wireline tools often employ data compression to send real time information back to the surface via copper wires, fibre optic cable can transmit data at 2.5Gb/s – more than 1,600 times greater bandwidth. That would allow users to deploy a camera tool, for example, and receive a live feed of up to 64 channels of HD, uncompressed video data.

Additionally, it requires virtually no NEWSBASE

One-stop op As a single-use tool, the electronic components of FLI tools do not need to be robust enough to survive prolonged periods downhole. If a typical job lasts 30 minutes to an hour, Purkis adds, components only need to be heat and pressure shielded to survive that long before they disintegrate.

That means they can be consumer-grade rather than military-grade, lowering costs and allowing designers access to the latest components on the market – e.g. the latest smartphone camera – instead of limiting parts to those which have been qualified for use in a well.

An hour of typical operation means that the power demand of a FLI tool is minimal. Instead of a 600-V power supply fed from the surface – coupled to a hefty power regulator in the tool – Purkis believes that small coin-cell batteries can provide adequate power for key components – essentially a sensor, an encoder and a fibreoptic transmitter – without the need for expensive, high-temperature lithium thionyl chloride batteries.

All of which also circumvents another of the service industry’s cost burdens. To mitigate against electronic components

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every metre along the cable’s length. It is especially useful in oil and gas operations because it can offer asset managers finegrain detail about the status of every point in a well. DAS in particular is “the talk of town,” Purkis notes, because it enables users to identify the exact location of leaks, monitor production and evaluate fracking operations in real time. This is where Passive FLI steps in.

Because all information processing is done via surface equipment, there are no components within the downhole tool itself, allowing Purkis to use the first commercial FLIs as a rapid, low-cost deployment system for DAS surveys. Currently DAS is either installed as a permanent system as part of the well completion, or temporarily installed and “A technician retrieved by a truck mounted Passive disruption and a suitcase, spooling system (similar to coil Purkis also explains his tubing and electric line). Both plans for two separate FLI rather than a are expensive, largely because disciplines: Active and Passive.

20-tonne artic of installation time and/or An Active tool features wagon and four capital equipment costs. A electronics and components dissolvable FLI system would designed to relay information personnel” slash both, enabling DAS to from downhole back to the Dan Purkis be economical in a far greater surface. Passive tools use just number of wells. the fibre-optic cable alone, no Movement on these first surveys is downhole tool, yet are capable of a number promising, with trials now secured in Texas, of impressive functions. These applications Oklahoma and Alaska, as well as interest form the bulk of Well-SENSE’s current from some other small onshore operators. workload.

Following these, Purkis hopes to be able to It is in conversation about recent take FLI-enabled DAS surveys to the wider advances in fibre-optic sensing – namely industry. distributed temperature sensing (DTS), While Purkis is bullish on the long-term acoustic sensing (DAS) and pressure sensing potential of both Active and Passive FLI, (DPS) – where Purkis becomes very excited. he is aware that every FLI tool will require Each technique involves sending laser light its own design and qualification – a Passive down a fibre-optic cable and analysing the FLI tool used for DAS will be less complex backscatter to determine information from becoming obsolete service companies routinely purchase lifetime inventories to guarantee that tools can be built and maintained without having to requalify replacement parts. FLI tools use the latest release of electronic components available at the time, with minimal requalification requirements. That represents big savings on advance purchases which may never be used.

Ultimately, these concessions to disposability allow Well-SENSE to build a tool whose raw cost is thousands of dollars, rather than hundreds of thousand. Operated by “a technician and a suitcase, rather than a 20-tonne artic wagon and four personnel,” FLI represents a radical reduction in cost from industry convention.

NEWSBASE

than an Active tool used for performing a directional survey. For that reason, Active applications will be slower to develop, though he hopes the uptake will be swift following the acceptance of Passive systems.

In the meantime, however, the company is seeking participation with anyone with an interest in the technology, from well operators to component manufacturers – “Anyone who wants to make this successful,” he says.

Longer term, his vision for FLI development is anomalous in the industry.

He concedes that: “FLI in itself isn’t that useful, it’s the applications you can put on it like a camera or a PLT or a gyroscope survey.” Lacking the expertise (and time) to design every possible system in-house, he wants to see the FLI system become an open-source platform for other developers to use, “in the same way that a smartphone provides a platform for all the thousands of apps developed by every and anyone.” In an industry notoriously protective of IP, that is indeed a revolutionary proposition.

Well-SENSE is confident that it has only begun to scratch the surface of what the FLI platform could do, even in a welcoming industry, it takes time to qualify such a radical departure from the norm. Yet throughout our conversation, Purkis has been evangelistic about changing industry perceptions and adopting new technologies.

If anyone is driven enough to drag the intervention market into the next century, it could well be Well-SENSE. n Contact: Well-SENSE Technology Ltd. Tel: +44 (0)1224 937 600 Email: dpurkis@well-sense.co.uk Web: well-sense.co.uk

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THE BEST OF 2016

Eelume gets kraitive with subsea robot

A new joint project unveiled by Statoil, Kongsberg Maritime and robotics developer Eelume will explore sea-dwelling robots for IMR operations

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phidiophobes beware: robotic snakes may soon be lurking in the Norwegian Sea. Kongsberg Maritime and Statoil have signed an agreement with Eelume to develop swimming, snake-like robots for subsea inspection, maintenance and repair (IMR).

Eelume, a Norwegian University of Science and Technology (NTNU) spin-off, has been developing the technology with Sintef, an independent research centre, for over a decade.

Opinion might be divided over whether these robots look like the future or the stuff of nightmares, but either way they have an undeniable cool factor. Their snake-like, flexible form allows them into confined areas which have proved difficult to access with existing technology. The ability to rotate the head of the robot fully also means that they can grasp and turn valves and handles in the same manner as an ROV manipulator arm – but without the bulky ROV attached to it. The demonstration videos released by Kongsberg illustrate just how dextrous the robot is.

Two versions are also highlighted: one with tail-mounted thrusters and one which is propelled by a swimming motion alone.

In the test pool, both appear tethered to umbilicals – a design which presumably is not intended for a final concept.

The group suggests that the robots would be permanently installed on the seabed – Eelume calls this a “resident solution” – and would then perform planned and on-demand inspections and interventions.

“Instead of using large and expensive vessels for small jobs, we now introduce a flexible robot,” explained Statoil CTO Elisabeth Birkeland. Perhaps a little diminutively, Birkeland likens them to “a self-going janitor on the seabed.”

They can be deployed at both existing and new fields where typical jobs include: visual inspection, cleaning, and adjusting valves and chokes – jobs which represent the majority of the costs of inspection and intervention.

“This partnership offers the chance to

Executive Vice President Kongsberg Maritime Subsea Division, Bjørn Jalving (second right) and Statoil CTO Elisabeth Birkeland Kvalheim (right), investigate the Eelume prototype. bring radical technology to the market, not just in what the Eelume robot can do, but how it does it,” commented Kongsberg Maritime Subsea Division executive VP, Bjørn Jalving. “It is a new tool that will enable operators to realise large-scale cost savings by introducing new ways of conducting routine tasks and helping prevent unscheduled shutdowns by reacting instantly when required.”

“With our unique expertise in the field of snake robotics Eelume is the first company in the world to bring these amazing robots into an industrial setting. Now we take the step from academia and into the commercial NEWSBASE

world to secure our place in the new and exciting subsea intervention landscape,” Eelume CTO Pål Liljebäck added.

InnovOil asked Kongsberg Maritime whether it had any further information on the cost, capabilities or time frame for the robot’s development. Given the early stages of the project the company was reluctant to reveal much, but said that its aim was to commercialise the technology specifically for oil and gas operations.

More work will be carried out over the next 18-24 months, and the group hopes to release further details towards the end of the year. n

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2016 Annual

Cracking the case of low-carbon hydrogen THE BEST OF 2016

3.

Carbon collects on the surface of the tin while the hydrogen floats feely

2.

As the methane floats up through liquid tin, intermediate molecules are formed before releasing the carbon and hydrogen atoms

1.

Methane molecules are bubbled through liquid tin heated to 700o to 1200o

Andrew Dykes speaks to researchers at the Institute of Advanced Sustainability Studies (IASS) who have developed in collaboration with the Karlsruhe Institute of Technology (KIT) a reactor that uses molten tin to crack methane into hydrogen – with no CO2 load

O

ne of the greatest hurdles facing hydrogen fuel cell technology is the fact that nature has already devised ingenious and relatively stable ways of storing hydrogen.

Unlocking the hydrogen atoms in methane (CH4) for example, typically requires steam reformation which, although fairly efficient, either produces carbon monoxide or carbon dioxide as a by-product. Given that any future hydrogen economy will be one driven by decarbonisation, this is not ideal.

Electrolysis is as efficient, if not better, but large-scale proton exchange membrane technology is not equipped to offer the levels of output required for a hydrogen transport system.

Another method may be on the horizon.

Towards the end of last year, a team from the Karlsruhe Institute of Technology (KIT) and the Institute of Advanced Sustainability Studies (IASS) under the scientific leadership of Nobel Laureate Carlo Rubbia published their work on a new way of cracking methane to produce hydrogen gas, with virtually no CO2 load.

The reaction vessel is the key to their process. The team bubble methane through a column of molten tin heated to between 750°C and 1200°C. The methane cracks into hydrogen and pure carbon, which collects on the surface of the tin and is recovered for use in standard carbon-black processes.

Using molten tin also allows for continuous operation; the tin simply acts as a reaction chamber and is not consumed or altered in the process.

Speaking from Potsdam, IASS Scientific Coordinator for Earth, Energy NEWSBASE

and Environment Cluster, Dr Stefan Stückrad, explained why they had taken on the challenge: “Based on our strategy to contributing to technological solutions for a more sustainable energy supply we were building on research that had been done in the past decades on the decarbonisation of methane cracking via different means such as catalytic cracking or plasma arcs.

In testing all these different approaches, researchers always encountered the problem of carbon clogging, which stopped a continuous process.”

Method reactor Settling on the aforementioned method, the researchers worked on the constituent parts of the process. A small reactor allowed them to concentrate on overcoming some of the fundamental hurdles such as materials, reactor design and gas dispersion methods.

“We primarily wanted to understand the process, the chemistry behind how to optimise reactor design - how much liquid metal and how much gas there should be in the reactor and the optimal operating conditions in terms of temperature and pressure,” Stückrad said. Initial trials saw a few hundred millilitres used, with flow eventually reaching around 1 litre of methane per minute.

Even though it remains in its early stages, their system looks pretty efficient. In one run without re-injecting, Stückrad said that up to 78% of the methane is converted into hydrogen. 21% is not converted and stays as CH4, and less than 1% forms intermediates such as ethane and other compounds. “It looks like these gases can also be re-injected and re-converted,” he added, “As their

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THE BEST OF 2016 The KIT Hydrogen Test Centre

chemical composition is also of carbon and hydrogen, only that the chains are a bit longer.”

Factoring in heat loss and heat recycling in the reactor, the process’ overall efficiency sits at just below 50%. The exact specifications of this depend on the temperature of the tin. At 1,175°C 78% of the methane is cracked first time, but the reactor will require more energy to maintain its temperature; at 900-950°C, around 60% of the gas must be re-injected, but the reactor requires less energy input.

At the commercialisation stage, balancing these efficiencies will ultimately be decided by the economics of both the input and output products.

Scaling up So far, the technology required all appears to be relatively plug-and-play. “The other components on the downstream side are technologies and machines which are commonly available,” Stückrad said.

“Nothing needs to be invented concerning gas filters or hydrogen separation units or gas recycling units. These are things you can buy on the market and just couple in.”

The exception is the system for removing the carbon black from the molten tin. The

first trials saw the team simply stop the reactor and skim the carbon off the top, which allowed them to observe more of the fundamentals behind the process. Later experiments used a nitrogen carrier gas to move the carbon, but a final system will be the focus of future development stages.

Stückrad notes that “a proper separation mechanism has to be validated. There are possibilities with inert gases, but there are also mechanical possibilities.”

We questioned the possibility of any hydrogen cyanide (HCN) formation during the reaction. Stückrad said none had been detected, though added that: “The chromatograph was not calibrated for that.”

Still, he continued, the absence of a catalyst such as nickel or platinum, and operating temperatures below 1200 °C make the production of cyanides “unlikely.”

In addition to separation, a method of cooling the hot carbon will also need to be devised, if it is to be stored and used safely.

Stückrad said that the low thermal capacity of carbon means that this is easily done via gas flow or cooling process. The lack of any oxygen in the system also lowers any risk of ignition. One of the next team’s next goals is to incorporate a recycling system for this process heat.

NEWSBASE

While the system copes with “intermediate” hydrocarbon chains, as well as traces of sulphur, it is unlikely to be robust enough to tackle other impurities. Particles such as water and sand are likely to interfere with the reactor meaning that – at present – methane would have to be scrubbed and cleaned before it could be cracked.

The next stage of the project will see the researchers work with industrial partners and funders to scale up the technology.

Discussions are now underway, and Stückrad is bullish on its potential, adding that the team is convinced they can scale up the reactor size by some orders of magnitude, to around 10 MW of hydrogen output. A plant of that size would produce up to 1,080 kg of carbon per hour – raising questions about what one might actually do with it.

Back in the black Total carbon black production was around 13 million tonnes in 2015, about 90% of which was used in the production of tyres and rubber. Already a US$14 billionper-year industry, as demand for carbon fibre and graphene increases, as well as the application of carbon to products like cement, plastics and steel, industry growth

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THE BEST OF 2016 Liquid tin in a machine for soldering printed circuit board components

should continue to reach over US$20 billion by 2022.

Steelmaking in particular uses massive amounts of coking coal, a relatively pure source of carbon. Around 70% of the 1.6 billion tonnes of steel produced in 2015 was dependent on coking coal, and each tonne of steel produced requires an average of around 500kg of it. As heavy industry increases efforts to decarbonise, molten tin reactors could provide a cheap and ready available source of carbon black to replace dirtier coke supplies.

At present, it also takes between 1.5 and 2 kg crude oil to produce 1 kg of quality carbon black, depending on carbon content of the raw material – making the IASS-KIT method considerably more economic.

One kg of methane will yield about 0.75kg of pure carbon and 0.25kg of hydrogen. US natural gas prices (around US$2 per mmBtu) are around US$100 per tonne or 10 cents per kg. At today’s carbon black prices (US$0.70 per kg) and hydrogen prices (US$5 per kg) the economics of the process look pretty attractive – crack 10 cents worth of methane and end up with 50 cents worth of carbon black and 125 cents worth of hydrogen, minus process costs.

Even in economies where methane

is much more expensive the economics still look fair. LNG – the most expensive methane source – is currently priced at about US$0.37 per kg.

“Compared with different electrolysis set-ups and methane steam reforming, the technology also looks pretty good from a life-cycle analysis (LCA) point of view – and in that analysis we completely left out the value of carbon,” Stückrad said. “It looks competitive from a price point of view and an environmental point of view. If we then allocate carbon a value – economic and environmental – it becomes an even better trade off.”

The beauty of the IASS-KIT solution is that it allows the production of two high-

Carbon Black powder NEWSBASE

value products from existing hydrocarbon infrastructure. Reactors could be fed by existing natural gas pipelines and sited at refineries and manufacturing plants for steel and the automotive industry, providing both raw materials and hydrogen supplies for fuel cell vehicles (FCVs) and energy storage.

For that reason, NewsBase believes the researchers’ technology could be highly disruptive to both the oil and gas market and the future hydrogen economy. While fuel cells must tackle issues concerning storage capacity and price, a cheap and abundant source of hydrogen – available anywhere there are natural gas pipelines – removes one of the largest barriers to the growth of an entirely new industry. Methane producers should get cracking. n

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Thermite makes P&A right Interwell is using thermite to melt rocks and seal wells, potentially transforming how the industry approaches P&A

T

he need for new plug and abandonment (P&A) solutions has pushed operators to look increasingly outside the proverbial “box.” In the case of Norwegian well to plug the well. In addition, because the management firm Interwell, this has meant reaction produces its own source of oxygen, disintegrating the box itself. no external supply is needed and almost no In 2012 one of the company’s technical other gases are produced, making it a sound advisors for P&A, Michael Skjold, floated choice for use downhole. a radical new idea: using thermite to So far, so good – but a lot of this melt materials in the wellbore, forming was unproven. Given the novelty of the an impermeable barrier and sealing the technique, there was a severe lack of well. Given the company’s history in scientific study which could qualify any of shallow and deep-set well barriers, well the process. Interwell therefore brought in integrity and niche completion products, certification agency DNV GL this offered a wealth of new in 2013, to help investigate potential opportunities in the and ultimately qualify the decommissioning space.

“Exothermic P&A Solution,” Primarily, Skjold says, (as it was initially referred to) the idea came in response to for commercial use. the need for cost reductions within P&A. As many Back to basics operators are exploring A lot of fundamental work options which dispense with was needed to underpin what the need for rigs, this method the team was attempting to could be deployed from a achieve. This meant studying single vessel with little external rock analogues, the processes equipment (the process would behind their formation and the also remove the need for resulting mineralogy and how cement or even coiled tubing).

“When ignited, well molten materials might If successful, this could streamline the P&A process thermite burns at bond within these formations.

In addition to funds from and potentially save significant around 2,500°C” the Research Council of time and money.

Norway, in 2014 Statoil and BP The idea itself is remarkably were also brought in as partners in a joint simple. When ignited, thermite – a industry project (JIP), allowing the company compound of metal powder fuel and metal access to a wealth of information on wells oxide (most commonly iron oxide) – burns and formations in the companies’ databases, at around 2,500°C, enough to melt through in addition to their perspective as potential tubing, casing and cement. It is also hot clients. The same year also saw patents enough to melt the surrounding rock, granted on the technology. bonding the materials together and – in Alongside this, Interwell ran exhaustive theory – forming an ideal barrier with which NEWSBASE

tests to develop a system which could be deployed in the wellbore.

In a video interview from 2014, Skjord explains: “The whole idea is to keep it as simple as possible. We want to make a manmade rock and to do this we want to enter the wellbore with a carrier device run on wireline.

The carrier device will be placed on a wellbore annular heat shield, and activated to provide enough energy to convert all materials into an everlasting deep barrier that hopefully will bond to the surrounding materials.”

Heating up Following the group’s 2014 feasibility certificate from DNV GL, they began scaled up testing of the tool. In 2015, they undertook onshore tests and small-scale subsea testing – crucial to determine whether the equipment would stand up to offshore conditions – before eventually building and testing a prototype in a specially designed test tank in Norway. This allowed Interwell to examine the system’s performance under simulated high-pressure, high-temperature (HPHT) conditions. The learning process also took the team to the Iceland Deep Drilling Project to study the behaviour of supercritical liquids – fluids above 347°C and at pressures greater than 220 bar – to support further tests of the P&A process in HPHT environments.

With over 4 years of experience and 200 tests under its belt, the company is now heading towards field trials in onshore wells in Canada and aims to have 4 pilot wells completed by the end of the year. According

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THE BEST OF 2016 The thermite melts the casing and surrounding rock, ensuring the plug bonds well to its surroundings

to a recent presentation, this would allow Interwell to commercialise the P&A tool fully for onshore and offshore during 2017, and for subsea operations in 2018.

Although it has been a long road since the idea was first mooted, progress on the

tool has moved at a pretty rapid pace – in an update in late 2015 Skjold noted that the team was “thorough but in a hurry.” n InnovOil hopes to revisit the tool later in 2016, following the results of Interwell’s field trials.

We will keep you posted on their progress.

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THE BEST OF 2016

Smart rocks play transformative role

Andrew Dykes speaks with the team attempting to create “smart rocks” – 3-D printed, sensor-packed models which will offer unprecedented insight into oil and gas-bearing microporous structures

F

or centuries, geologists have sought to understand what goes on inside the minute porous structures of oil-bearing rocks. Now, sensors embedded within the rocks themselves may be able to tell them.

The European Research Council (ERC) has recently awarded a 3 million euro (US$3.35 million) grant to a team of engineers and scientists at Scotland’s HeriotWatt University to achieve just that. Led by Professor Mercedes Maroto-Valer (below) – who holds the current Robert M Buchan Chair in Sustainable Energy Engineering – the research team is seeking to create exact replicas of porous rocks using 3-D printing.

By embedding micro sensors in these “smart rocks” as they are laid down, the team can then run experiments to collect information on porosity, flow temperature and more, at a scale which has never been achieved before.

Professor Maroto-Valer heads a nearly 30-strong interdisciplinary team at the university, tasked with developing novel chemical and engineering solutions which can aid the pursuit of energy, and with a particular focus on clean and sustainable technologies. Although trained as an applied chemist, she has spent most of her career in chemical engineering departments, and now works with a range of expertise “all the way from mechanical and reservoir engineers to chemists and geologists.”

In an interview with InnovOil, she explained that Heriot-Watt had been examining the area of research for some time, within her own research group and others. “We have been working for quite a number of years looking at flow in porous media for different

applications, either oil and gas or industrial processes. But as with any project looking at the subsurface, it can be very difficult to see what’s actually happening, particularly at the pore level.”

“We realised we needed to approach this from a different angle,” Maroto-Valer said.

“Rather than getting cores and trying to instrument them, we wondered if we could actually print the rock – or something that would be very similar in terms of its physical and chemical properties.”

The solution, it transpired, lay just across campus in another of the university’s departments.

Control, print “We started talking to colleagues at HeriotWatt from Manufacturing and from Sensing about research, in terms of the challenges that we were facing which had stopped us pushing this into the frontier,” she explained. It was through these discussions that Professor Maroto-Valer learned how advanced sensing technology had become – especially that it could withstand the temperature and pressure of downhole conditions, and could be placed with minute accuracy.

“We came up with the idea to 3-D print porous rocks, get the sensors in and then run our flow-through and standard experiments,” she continued.

First, core samples are 3-D scanned to create a highly detailed digital model. This model then allows the team to print an exact replica of the core, while sensors can be placed in areas of particular interest – for example, where there are specific fractures or particularly challenging microporous structures which warrant investigation.

These sensors can measure and report on a NEWSBASE

number of variables, she added, including temperature, pressure, pH and fluid/gas composition. “They can do really incredible things in terms of being able to collect information within a very small microenvironment. They can not only sense a particular parameter, but communicate that information to the outside,” she continued.

“We know from work that has been done here at Heriot-Watt before what type of sensors we can use, what type of optical fibres, how small we can do them, how precise we can position them, and what type of information they can collect at the pore level.”

These printed cores, formed from polymers, glass and steel, can then be subjected to the same conditions as the reservoir, enabling a far more in-depth understanding of oil, gas and water transport behaviours. This should allow chemical engineers, for example, to test how surfactants will interact within the pore structure in EOR applications, or which structures are best for holding CO2 in a carbon-sequestration scenario. “We will be able to tell you what happens in that core in detail you would not have been able to get before,” she said.

The group’s intention is that these printed models should – as much as possible – mimic the core samples the industry is used to.

“Right now we are aiming for typical core size – around 1 inch (25 mm) in diameter is quite standard nowadays. Its length is just a matter of how many layers we want to print. Our intention is that they will look basically the same as if you were to drill a core – but you won’t have to actually drill it,” she explained.

The potential implications of that capability are substantial. As 3-D scanning and seismic data become even more sophisticated, geologists of the future may never have to remove cores from a reservoir to understand it accurately. With sufficiently detailed scanning and digital models, it may be possible to print samples from any part of a formation; producers could understand how the pores are structured and how fluid or gas will behave inside them before any drilling has even begun.

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Sensors embedded within the rocks could help producers understand how to squeeze more oil and gas out of them

Porous possibilities Retrieving the information should also be straightforward. Sensors’ data are sent out of the core using tiny optical fibres, also incorporated within the layers of the model as it is made. These high-bandwidth fibres will deliver that information in real time, meaning researchers should not only have access to more detailed results, but they should also have them faster than has been possible before.

Professor Maroto-Valer believes that the knowledge gained from these sensors will also help to improve current structural models, making them much more robust.

“Rather than not knowing what happens [in a particular formation] or having to model or predict it, you can visualise the whole process,” she added.

The level of detail and complexity that these printers can achieve is staggering. “We’ll be looking at micron features,” she noted.

“That’s how far you can go. It’s a compromise between how far you want to print, how big you want to make them and how many sensors you want to insert…it’s all a balance between how small and how complex the structure looks. But the technology itself can go well into the micron range.”

In addition to understanding fluid flow in oil-bearing rock, the group is bullish on the potential of its research for numerous other fields: “The applications are mindblowing,” Maroto-Valer enthused. As well as the aforementioned opportunities in hydrocarbons, water and gas recovery – hydraulic fracturing is a notable candidate – it holds intriguing prospects for geothermal exploration and industrial processes, all of which are controlled by pore-level mechanics.

In particular she highlighted gas drying in a refinery, a process whereby wet gas is passed through porous media and liquid and water vapour is removed via adsorption.

Incorporating sensors into 3-D printed versions of these systems would enable a much greater understanding of how gas interacts and moves through this media. “If you can understand all those processes at a

fundamental level you can optimise them,” she added.

Going beyond that, there are porous media everywhere which could benefit from this kind of analysis, even in the architecture of organs in the human body. The team is optimistic that there could be medical benefits to its work too.

and more specific sensors, even more variables can be measured in the pores. Professor Maroto-Valer is even exploring the feasibility of printing these pore structures at nanometre-scale.

The five years of research funded by the ERC is sure to throw up its fair share of challenges too – “It all sounds easy but then we actually go in the lab…” she laughs – but the team is confident that it has an established technique and the right skills in place.

Although still in its early stages, management and logistics are beginning to come together, and the team is eager to get started. There has also been interest in commercial applications, and the team is currently in discussions with several parties.

What is perhaps most pleasing about the project is its multi-disciplinary involvement, something the commercial oil and gas industry is only just beginning to embrace.

Professor Maroto-Valer, however, is a firm believer in the process as an essential method of pushing scientific understanding. “When you are addressing a complex challenge it is very difficult to do it just within your own lab, or your own discipline… [Sometimes] the only way to move beyond the state of the art is to bring in other elements from other areas, techniques which might have been developed for another purpose maybe, and that allows you to move forward,” she said. “Otherwise you get stuck in your own ways of thinking.” n

Five-year plan In the long term, discussions are already taking place as to how far the technique can be pushed. It is possible that with refinement

Contact: Professor Maroto-Valer Tel: +44 (0)131 451 8028 Email: m.maroto-valer@hw.ac.uk Web: www.hw.ac.uk/

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THE BEST OF 2016

Spotting earthquakes from inner space Using satellite data and computer modelling, geoscientists may now be able to analyse and predict seismic events caused by wastewater injection, writes Ros Davidson

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ncreasingly, the US is feeling the effects of earthquakes linked to wastewater injection by oil and gas operators. In the central US, in states such as Texas and Oklahoma, between 1973 and 2008 there was an average of 24 earthquakes a year in the US with a magnitude of 3.0 or larger on the Richter scale. But from 2009 to 2015, there were 318 yearly, an increase of more than thirteen times.

While some are unconvinced, the United States Geological Society (USGS) has unequivocally stated on its website: “Wastewater disposal is the primary cause of the recent increase in earthquakes in the central United States.” Fracking can also cause induced quakes, but because the volume of liquid is much smaller, the number of quakes is much smaller.

Wastewater comes from a variety of sources, whether as a by-product of extraction, or left over from high-volume fracking. Whatever its origins, about 2 billion gallons (7.5 billion litres) of it are injected daily into an estimated 180,000 wells in the US, mostly in Texas, Oklahoma, Kansas and California.

The accelerating seismicity means that an estimated 7 million of people and their communities are at risk, the USGS warned in its annual seismic outlook published in March. Insurance rates are higher for the oil and gas sector in the affected areas, and in some cases operators are being sued for quake damage. The publicity is also tainting the industry: the current popular buzz is that only fracking causes quakes, even although wastewater injection has been identified as the most frequent culprit.

But a new way to look at the issue is now emerging. A team of scientists led

by Arizona State University has devised a method which could be used to predict or prevent induced quakes. Combining satellite radar measurements and a new computer model which predicts underground “pore

elasticity,” the tools could prove useful in aiding operators and state or federal agencies to minimise the danger.

Uplifting results The research, conducted by geophysicist Manoochehr Shirzaei of Arizona State University and colleagues, is more than ground-breaking, so to speak. Co-authored between William Ellsworth of Stanford University, Kristy Tiampo of the University of Colorado Boulder, Pablo González of the University of Liverpool and Michael Manga of UC Berkeley, and published in the respected journal Science, the work is among the first to measure – definitively – uplift on the ground above wastewater wells.

Their model also shows how water pressure in pores in underground rock can radiate out from wastewater wells to reach fault zones, where it could trigger small or moderate quakes. Even small quakes can lead to larger seismic events as they destabilise a region’s once finely balanced geology. The implication, as Shirazei told InnovOil, is that better monitoring would enable safer injections: “We could minimise the probability of large quakes – that’s a huge thing,” he said.

The research could guide where wastewater wells should be located – such as in what sort of geology and at what depth – and when injection should be slowed or halted. It is crucial to exactly how slowly injection should be tapered off.

In September, Oklahoma regulators ordered the shut-down of 37 wastewater wells connected to the Arbuckle formation after a tremor that tied as the state’s worst ever. The closures were ordered over a period of 7 to 10 days, for fear of causing more earthquakes if the volume of wastewater injected along a faultline were suddenly reduced. The regulators‘ move was based on current knowledge, but Shirazei and his co-authors have found that there NEWSBASE

could be greater pore pressure underground even after injection was halted for some time.

So SAR, so good To achieve these results, the researchers analysed more than three years of radar data from the Japanese Advanced Land Observing Satellite (ALOS), which contains interferometric synthetic aperture radar (InSAR), a remote satellite-based sensing technique.

Synthetic aperture radar uses pulsed radio waves which are transmitted over a target area. The echoes of these pulses are

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THE BEST OF 2016 JAXA’s Advanced Land Observing Satellite (ALOS)

then received and recorded, and the process is repeated. Multiple signals are sent from a single moving antenna and the successive signals, when processed, offer more detailed, higher-resolution images than with a single pulse. InSAR uses two or more of these images, using the differences in wave phases to measure surface deformation in millimetre-detail.

Using this technology, researchers looked at the highly accurate measurements of the ground from May 2007 to November 2010 in and around Timpson, Texas, an area which also contained four high-volume disposal wells.

They chose that location in large part because they were able to access continuous satellite readings, as well data from the state on injection volumes. There were wells at different depths, and there was variable geology.

They found that the earth’s surface around two of the wells bulged by as much as 3mm a year. Uplift was detected up to 8 km from the wells. “For this Timpson study area we got lucky and could see the deformation,” Shirazei said. Many previous studies have found that ground can subside when oil, gas or water is extracted, but this research is among the first pieces of research NEWSBASE

to find uplift after fluid is pumped into the ground.

The wells in Timpson where there was more deformation were shallower, he told InnovOil, and the surrounding rocks were more compliant and softer, suggesting they may have deformed more. The other wells nearby were in denser rock, and pore pressure could thus have been prevented from reaching crystalline basement rock and triggering quakes, he added.

The researchers also plugged the radar data into their new poro-elastic model, along with histories of injected water using data from operators that must be submitted to

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THE BEST OF 2016 Satellite view of Timpson, TX. Source: NOAA

the Texas Railroad Commission. They found that a front of pore pressure – starting at the injection site – had moved underground, eventually affecting faults and possibly triggering quakes between depths of 3.5 and 4.5 km, depending upon the specific geology of a location. The model uses geological and hydrogeological information.

Indeed, two years or more after the data were gathered, in 2012 and 2013, a swarm of small quakes hit the Timpson area, including a moderate one of 4.8 magnitude, the largest ever recorded in east Texas. While it would support the team’s theory, the results are not definitive: the quakes were adjacent to the wells where there was less bulging in the earth’s surface, and about 25 km from the wells where there was more.

One of their findings – that seismic activity can still increase even after a cessation of injection operations – could be because it takes time for the wastewater to travel underground, or because there could be new stresses arising if injection is suddenly stopped. “If you stop injection today, it’s possible that earthquake activity goes on for the next decade or so,” Shirzaei commented, drawing on the Timpson study in particular.

Of wastewater wells in general, he told InnovOil that ideally injection should not be shut down suddenly, as it may cause a sudden reduction of normal stress on optimally oriented faults and could even trigger earthquakes. He also said that, in general, pore pressure in wastewater wells can remain high for a “long time after shut-down, thus the probability of the large earthquakes remains high in the region for a long period of time.” Equally, quite often the pressure can return to normal relatively quickly and injection can resume.

Model for monitoring The research has been well received, especially for successfully extracting the earth’s “crustal strain” from the complex InSAR data, which also picks up factors that can change year-round, such as vegetation.

Neither are the results fully conclusive.

Some scientists have noted, for example, that rock stiffness can mean there is more pressure, not less. Others have also commented that the example studied

might have been more satisfying had more deformation been detected above the deeper wells specifically.

Nevertheless, if the research can be replicated, its applications could be wideranging. Not only could the location of wells be fine-tuned, but the injection itself could also be customised, based on the findings of real-time monitoring, so that a critical stage of deformity is never reached.

Perhaps not surprisingly, Shirazei has meetings set up with oil and gas operators and government agencies so far in Texas, Oklahoma and Colorado and has begun speaking to the US Department of Energy (DoE) regarding additional funding to NEWSBASE

expand the team’s research.

He says the monitoring itself not expensive. For example, some space agencies may even offer similar satellite data for free.

States also collect injection data – daily in the case of Oklahoma, monthly in Texas – meaning most of the raw information should be readily available. The researchers, in addition, have made their poro-elastic model public (although it does require a supercomputer to handle it).

With further work, and hopefully increased co-operation between regulators, data providers and the industry, techniques like InSAR could become a powerful new tool in the monitoring and safety arsenal. n

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A HUD of the pack THE BEST OF 2016

US Navy engineers have developed a next-generation helmet, showing divers live information via a head-up display

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n the sea floor, seeing clearly is difficult. For divers working at depths of 100 metres or greater, every extra bit of information or assistance can go a long way.

With robots, ROVs and more sophisticated equipment, it is easy to forget that human divers still have to perform a number of complex subsea tasks. While the industry’s focus on safety has undoubtedly improved over the past few decades, the pace of updating equipment and work processes has remained slower.

But with many new innovations aimed specifically at commercial divers, the pace seems to be changing. InnovOil has already featured Etro’s heated diving suits and Photosynergy’s Lightpath umbilical system – and June brought news of an intriguing new piece of kit from the US Navy.

Engineers at the Naval Surface Warfare Center Panama City Division (NSWC PCD) have devised a diving helmet with an in-built head-up display (HUD). The high-resolution Divers Augmented Vision Display (DAVD) is embedded directly inside the helmet and allows users to see far greater information and detail on their task, from a number of different sources.

This system is capable of displaying sector sonar – a topside view of the diver’s location and dive site – as well as text messages, diagrams, photographs and even augmented reality videos, and all in real time.

inside the dive helmet instead of attaching a display on the outside, it can provide a capability similar to something from an ‘Ironman’ movie. You have everything you visually need right there within the helmet.”

Tony Stark would indeed be proud.

Naval Sea Systems Command (00C3) is also developing enhanced sensors – such as miniaturised high-resolution sonar and enhanced underwater video systems – to enable divers to view higher-resolution images up close, even with almost no water visibility. In future, these underwater vision systems could then be fed directly into the DAVD HUD. Commercialising DAVD or a similar system could have a major impact on divers in the oil and gas sector in particular. Given their need to locate and modify complex subsea equipment in difficult conditions, operators could improve the efficiency and safety of manned dives. As Reddit user and diver gnar-dar commented: “It’s about time! I worked as a commercial diver for 7 years wearing these exact Kirby Morgan dive helmets... So

Stark comparison The addition of real-time operational data should help divers to work faster and safer, offering more information than pre-dive briefings alone. The HUD can help guide them to the worksite or a target, display details about the area or piece of equipment and help increase awareness of other potentially hazardous features around them.

All of this can be configured by each diver – e.g. the positions of each data feed – or they can simply turn off the HUD when it is not required.

The DAVD was devised by Underwater Systems Development Project Engineer Dennis Gallagher and his team. Gallagher added: “By building this HUD directly NEWSBASE

much bottom time is wasted simply trying to find the worksite, with someone on a radio on surface watching you on a sonar feed and trying to relay it to you.”

So far, the engineering team has demonstrated the technology to more than 20 US naval divers. Although full deployment looks to be a year or two away, the team is now working on phase two, where components are being designed to include both helmet systems and full face masks. Divers are scheduled to conduct inwater simulation testing in October 2016.

Phase three is set to begin in 2017 to harden the system for expanded field testing with various US naval commands. n Web: www.navy.mil/local/NSWC

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Closer inspection with TSC THE BEST OF 2016

TSC Inspection System’s David Parramore discusses the benefits of ACFM®, and the company’s innovation – the ACFM® MagCrawler™

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t often feels like there isn’t much you can’t attach to an ROV these days.

The advent of more manoeuvrable and versatile vehicles, coupled with major advances in electronics and sensing technology, has transformed industry capabilities and expectations. That brings immense benefits to operators, but also new challenges in incorporating complex equipment into an enormous number of vehicle designs.

Now, alternating current field measurement (ACFM®) joins the ranks of inspection techniques which can be deployed remotely. ACFM® is an electromagnetic inspection technique which uses an alternating current to detect defects.

It works by introducing AC into the surface of a structure, component or pipeline.

Cracks in the material’s surface disturb the current’s electromagnetic field, and the returned signal is analysed in real time, A diver measuring pipe integrity using ACFM alerting the user to the presence, size and depth of a defect or crack. since become a mainstay for use in diver and The immediacy and accuracy of the Enter the MagCrawler™ diverless inspection operations. technique offers major advantages when The ACFM® MagCrawler™ allows this TSC Inspection Systems is a UK-based compared to other non-destructive testing inspection technique to be carried out by a firm established in 1984 as a spin-off from (NDT) methods. Independent testing has tracked magnetic crawler vehicle. This is of University College London. shown that ACFM matches the particular use for situations requiring accurate Its founding team were performance of rival techniques inspection of subsea welds, but where access recognised leaders in the such as method magnetic can be difficult or costly to reach with divers. fields of NDT, robotics and particle inspection (MPI) The crawler is magnetically attached to fracture mechanics, and the for inspecting underwater the inspection surface. Two rubber caterpillar company now offers an array structural welds, but offers tracks provide both traction and accurate of inspection services and significantly lower instances steering. The vehicle can then be piloted equipment. of missed and spurious signals directly down the structure, if near the splash Having begun as a software when compared to MPI and zone, or can even be delivered and deployed company for testing fatigue in conventional Eddy current

by ROV, to the inspection site. components and tubulars, TSC testing.

Parramore adds: “Although it’s possible developed ACFM as a method It can also be performed to get good access to structures with ROVs, “We believe we’re of checking and verifying through coatings and paints, sometimes space constraints prevent you the results and effects of test meaning it can be carried out getting in close enough. Placing ACFM on a the leaders in procedures in the early 1990s. far more quickly, economically MagCrawler was a way we could overcome the field” Since then, NDT has become and safely than techniques like that, and particularly overcome the issue of its core business, with ACFM at MPI. ROV stability near the water surface.”

David Parramore the forefront.

ACFM was developed by In order to ensure the operation could Most recently, this includes the ability to TSC Inspection Systems, with support from be performed accurately and remotely, TSC carry out ACFM inspection with a magnetic BP, BG, Conoco and Royal Dutch Shell developed a new ACFM array probe. While crawler deployed from an ROV. who were keen to improve the reliability divers might use a pencil-shaped probe to InnovOil spoke to TSC’s engineering & of underwater inspection dramatically, enable very accurate inspection, Parramore operations director, David Parramore, to find reducing the reliance on the operator and explains: “We recognised that as soon as you out more. provide auditable inspection records. It has go to remotely operated inspection tasks, the NEWSBASE

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ACFM® MagCrawler

precision capability of a diver is no longer there…so we overcame that by making arrays.” These are sensitive to changes over the surface area of the probe, allowing for wider and more accurate coverage for remote use.

The resulting array probe is accurate to within 10mm or so, and means that in addition to crawler deployment, it can be used on ROV manipulator arms and in other configurations. ACFM can still detect and size defects as small as 15mm long by 1mm deep in welded connections, even when inspected through a protective coating.

Advanced control software means the crawler can also navigate the wide range of complex weld geometries found on both fixed and floating structures. Power is supplied to the array by the ROV or crawler, typically requiring 24 V at a couple of amps.

It can manoeuvre easily on flat surfaces or tubulars with a diameter greater than 30 inches (760mm). Motorised adjustments of probe position can be made in both parallel and transverse directions, allowing full coverage of the area to be inspected. The probe is held in contact with the inspection

surface using passive compliance, ensuring that the probe is aligned correctly at all times.

Additionally, 360° rotation means that the probe can fully inspect flange welds.

Crawler deployment also means that ACFM can be used to inspect ship hulls, “particularly large ship hulls which are semipermanently in position, such as drilling ships and semi-subs,” Parramore says.

The ability to perform checks on welds with ROVs and crawler vehicles significantly reduces costs – an ROV-equipped vessel can be typically three or four times cheaper than a similarly capable diving support vessel (DSV).

2016 and beyond December 2015 saw the ACFM® inspection technique accepted by classification society Lloyds Register. The endorsement covers manual and robotic deployment of ACFM® for topside, subsea and splash-zone inspection applications.

Under Lloyd’s Register certificate RSS/ MNDE/0009, the TSC Amigo™ and U31™ Systems have been accepted for the in-service examination of structural welds, heat-affected NEWSBASE

Array probes overcome the issue of taking accurate measurements from an ROV

zones and adjacent parent materials, in uncoated or coated steel structures, with the intention of detecting surface breaking discontinuities.

In 2016, the company will also be expanding the use of the ACFM® NodeScanner™, a dedicated device for complex node inspection on welded tubular joints.

“Now that we can perform ACFM without using a diver, it opens up the opportunity to further reduce inspection costs – and we believe we’re the leaders in the field,” Parramore says. “While there are comparable ultrasonic techniques, they require much higher degrees of accuracy, making them extremely difficult to deploy via ROV.” TSC’s year is already filling up with potential projects in both the Norwegian North Sea and Gulf of Mexico. If everything goes to plan, the ACFM MagCrawler may well be visiting a structure near you very soon. n Contact: David Parramore Tel: +44 (0)1908 317 444 Email: info@tscis.com Web: www.tscis.com

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The hub of the matter THE BEST OF 2016

The Subsea Power Hub, developed by Aberdeen-based ECOG, is a seafloor turbine which the company hopes could change the economics of powering subsea equipment

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owering oilfield equipment is difficult; powering it on the seafloor several kilometres from the surface is even more so.

Typically, that can be done from the surface via long tiebacks. Indeed, for multiphase pumps, compressors and other turbo-machinery, which can require megawatts of electricity, surface power is likely to be the only economic solution. But with failure of these umbilicals being one of the most common reasons for downtime and lost production, siting power generation infrastructure at the equipment itself could help increase safety and improve margins.

Recognising the need for more sustainable, reliable subsea power, East Coast Oil & Gas (EG-OG) was set up to support the development of its renewable innovation – the Subsea Power Hub (SPH).

Founded in 2013 by managing director Richard Knox and engineering director Rob Cowman, EC-OG has established a sound reputation in engineering services covering wellheads, Xmas trees and intervention systems, while the SPH has continued to pique industry interest.

Transportable turbine Based on a familiar subsea template, the SPH supplies electric power from up to three turbines mounted in the centre of the frame.

Typical seafloor current strength is around 0.4 m/s, meaning each turbine will deliver an average base-case output of 300 kW per annum, and the largest models will produce around 150kWh per year. Hubs can also be clustered and configured by a distribution network for larger project footprints.

An intelligent energy management system (IEMS) optimises battery life by considering the energy available in ocean currents and the repeat performance of the unit in powering battery system, helping to increase design life far beyond battery-only systems.

While typical battery systems may last around a year alone, the SPH can extend this indefinitely, at full capacity over the intervention period.

This also allows the SPH to power continuous monitoring, control and communications systems, as well as intermittent high-power tasks, such as high bandwidth communications.

The lightweight frame and overtrawlable structure allow the SPH to be fairly transportable, and to be deployed from a standard construction support vessel (CSV).

This also permits it to be re-deployed and re-used. EC-OG also plans for a flexible business model which would include SPH as a rental system, offering producers power supply with no CAPEX required.

Since 2013, EC-OG has garnered significant investment and support for the project such as several large grants from the Scottish government and Scottish Enterprise as part of the latter’s High Growth Ventures Unit. More recently, it secured a further GBP1 million (US$1.3 million) in external investment from Castle View Ventures

The overtrawlable SPH template can hold up to three turbines

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and the Scottish Investment Bank, which will take the SPH through to the in-house prototyping phase.

According to EC-OG, a single-turbine prototype should be complete by the end of November. A full, three-turbine prototype is expected to follow in 2017.

“It’s a very exciting time here at EC-OG,” Knox told InnovOil. “Over the next year, the team will be working hard to push forward with the commercialisation of the Subsea Power Hub. We are fortunate to be in a position where we have had concrete votes of confidence in the strategy of the company.

It’s great to see that people are reacting positively to our innovative idea.” n Contact: Graceann Robertson Tel: +44 (0)1224 933 301 Email: info@ec-og.com Web: ec-og.com/

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An x-ray of hope for stuck tools THE BEST OF 2016

Visuray is using x-rays to give operators detailed 3-D pictures of the inside of their wells

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With its unique downward focused X-ray source, the VR90 tool is shown imaging the fishing neck of a wireline tool stuck in a well

hat if you could see inside your well? The instinctive is answer is that with various imaging techniques, we already can. Cameras, electrical, acoustic and combination imaging techniques already offer a multitude of methods which enable us to examine or map the condition and layout of the wellbore – yet the value of those images depends on what exactly you need to do.

The major problem with optical imaging is that it requires a transparent fluid to be of any help – few cameras can see through opaque liquids. Ultrasonic techniques work with clear fluids but are less useful for fluids contaminated with particulates.

Stuck tools represent a particular problem.

If a tool gets stuck downhole during a well intervention, options are limited in terms of its retrieval, especially when intervention engineers or slickline operators cannot see exactly what is going on. Impression blocks can be used, but do not offer much clearer insight than that suggested by a misshapen block of metal. Furthermore, even if the tool can be located and its position established, it is usually very difficult to retrieve it one piece with such a limited view.

Visuray’s approach is a departure from the industry norm; in a process called fluid-based surface imaging, it uses x-ray backscatter to produce highly detailed 2-D and 3-D images of hardware in the well.

Seeing is believing The firm offers downhole x-ray imaging as a commercial service to operators looking to their wells in greater detail – particularly useful when undertaking well interventions.

Its proprietary system, the VR90®, is a downward-facing x-ray tool which can be deployed downhole via coiled tubing and run via all types of electric wireline.

Inside the VR90 is a digital x-ray detector with a pixelated array based on applications from the medical sector, as well as a miniaturised, high-output x-ray source.

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To power this, Visuray developed a compact, ultra-high output power supply which enables the 180-kV source to emit high-energy x-rays, using an electron beam current of 1mA. All of this is housed in a system measuring 3 5/8” (92mm), around 27.5 feet (8.4m) in length and weighing 236kg.

Miniaturising this technology was one of the Visuray team’s greatest challenges. The firm’s founding CEO and chief technologist, Phil Teague, explained to InnovOil: “We generate and control very high voltages within a very narrow grounded tool housing.

State-of-the-art industrial power supplies of an equivalent voltage are similar in size to an oversized suitcase but only operate at room temperature – so reducing the size of such power supplies into a wireline deployable 3 5/8” tool while designing for hightemperature functionality was one of the key successes of the technology development.”

The detector itself is made up of six individual tiles measuring 128x128 pixels, each pixel of which measures 100 square micrometres. Information gathered by the array is then sent back to the surface for processing, generating 2-D and 3-D images for analysis by the operator. Rather than this being taken away to be processed, images can be produced in near real time, allowing intervention managers to make faster decisions about their wells.

The actual process enabling this is more complicated than it may sound. In backscatter imaging, the radiating source and the detector are positioned on the same side of the examined object. Traditionally, the detector is calibrated to form an image from the photons which are scattered and returned by the object – yet the metals used in oil wells tend to be very dense and will readily absorb photons. In addition since the object is immersed in the well fluid, the signal which returns is mostly comprised of backscatter from the fluid. That rules out using a simple x-ray backscatter setup.

Visuray navigates this problem using its

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THE BEST OF 2016 Tool in well

2-D image

3-D image

Fish

Wire ball

Wrench

In all three cases, VR90 images allow operators to select the correct fishing tool for successful recovery.

proprietary technique. Fluid-based surface imaging assumes that photon scattering occurs mainly in the fluid with only a negligible contribution from the object itself.

That means that the amount of scattering observed indicates the distances between the detector and the face(s) of the metal object. Using this principle, Visuray’s system reconstructs a 2-D and 3-D image of the object based on these spatial variations.

This inherently safe method can deliver a clear picture across all production fluids, even when they contain particulates such as sand or rust. It can also image hardware as it lies, without the need for cleaning, additional fluid displacement or chemical conditioning, all of which offers a considerable time and cost saving compared to other techniques.

Gone fishing Another particular advantage – though by no means a necessity – is that the 3-D image can be rendered in other ways. In conversation with InnovOil, Visuray demonstrated a 3-D printed resin model of a wrench, which had been modelled from a 3-D x-ray image. While it is unlikely to be useful to

all operators, having an actual model of the tool to examine is a powerful physical tool to show just how accurate and informative the technique can be.

Currently, the VR90 works at temperatures of up to 100 °C and pressures of 20,000 psi, though recent improvements will see a 125 °C-rated model brought to market later in 2016. Teague says that this covers temperatures found in “the majority of wells,” but rules out high-temperature applications for the moment. “Wells with significantly higher temperatures, such as 150 °C, are currently prohibitive to the technology.

However, we are continuing to increase the temperature rating of the technology and believe that we will be able to service the [these] wells in the future.”

Visuray remained drawn on the provisional cost of the service – Teague told InnovOil that the service was “comparable to the cost of running other imaging services” – but added that once the technology had proved its worth, a value pricing method would be agreed with its customers.

Promisingly, those potential customers could be major operators – Statoil, BP and Royal Dutch Shell all contributed funds to the company’s initial start-up, with additional funding supplied in a later round by other joint industry partners.

So far, Teague said, “industry response to the technology has been very positive.”

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Late 2015 saw the company secure its first commercial well operation, where it used the VR90 to take 2-D and 3-D images of a coiled tubing BHA disconnect in an onshore well in the Netherlands, for TAQA Energy. As a result of the image accuracy, the assembly was retrieved in a single fishing run.

Beyond its direct use in imaging, Teague believes the technology holds a number of other possibilities that the company hopes to explore in future, adding: “It is possible to envision applications where it can be employed as a well integrity diagnostic method. The way in which we produce X-rays also eliminates the use of radioactive isotopes, [meaning that] many of the traditional oilfield measurements which rely on radioactive materials could be replaced with this core technology, in addition to new techniques and measurements.”

Overall, it is a highly promising innovation for an industry just beginning to get to grips with x-ray techniques in areas such as asset integrity and inspection. With even more focus being placed on cost and time efficiency, in new wells and old, the accuracy offered by the VR90 could make it an invaluable tool for the tech-savvy well manager. n Contact: Angeline Tse

Email: angeline.tse@visuray.com Web: www.visuray.com

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THE BEST OF 2016

SeaCaptaur: solving big problems in Small Pools

Alan Roberts of SeaCaptaur discusses the company’s storage, production and delivery system – technology which could help unlock the billions of barrels trapped in the world’s Small Pools

“T

he new era of oil and gas sees less meetings in bars, and more in coffee shops,” quips Alan Roberts.

He is explaining the conversations which led to the creation of his latest venture – SeaCaptaur – and its unique storage, processing and delivery system: a combination of technologies designed to enable the economic development of small offshore oil deposits. Together with co-founder Max Begley, Roberts is hopeful that the innovation will play a major role in unlocking more than 1,000 of the world’s so-called Small Pools (which possibly hold some 2-3 billion barrels) that defy current development economics.

In a nutshell, the eponymous SeaCaptaur System uses an unmanned production spar buoy anchored by an articulated joint to a subsea storage tank. This is maintained by a small tanker, which may also service the facility when visiting to lift product. Small moving objects in the ocean present a range of issues with respect to access and DP vessel performance, which becomes the essence of many of the design elements. The majority of the world’s Small Pools range in size from 5-25 million barrels in water depths of less than 300m, which to date has been the modelling limit of the system.

The spar buoy dimensions are not scalable without an adverse impact on its hydrodynamics, so it is compelled to remain small, and therefore limited to 10,000 barrels of oil per day, but with significant scope for high water cut (at the expense of oil rate) by use of the subsea storage tank in the process circuit. The subsea tank, unlike the spar buoy,

is scalable from 45,000 to 750,000 barrels of oil – the ultimate limit being the gantry clearance in the world’s large dry docks.

Most crucially, SeaCaptaur’s focus has been on reducing the unit technical cost (UTC) – both CAPEX and OPEX – with a target of 50% compared to conventional platforms or FPSOs. More pressing is the fact that “in today’s environment, that UTC will have to be around 50% of the prevailing oil price,” he adds. The system facilities’ cost-sharing between production locations up to 100 km apart and serialisation of developments has the ability to bring the UTC down to US$25 per barrel.

Buoys will be buoys Over that coffee in 2012, conversation turned to ideas which might save the fortunes of a number of ASX (Australia) listed E&P juniors struggling to commercialise small resources with FPSO technologies. “Those ASX juniors only had a chance if they could develop at 50% CAPEX and OPEX of an ambitious FPSO,” Roberts explains. Moreover, that CAPEX would also have to include the cost of wells, subsea and pipeline infrastructure – typically around 40% of the project’s perbarrel cost – Roberts said their real objective was closer to a 70% cut in production facility costs.

One of Roberts’ previous roles was in project management for Australia’s Western Mining. In particular, he put together a concept for the company’s East Spar field – an idea never employed by Western Mining but later revisited in the 1990s by the field’s subsequent owner, Apache Energy. This formed the basis for the Apache East Spar, the NEWSBASE

first of its kind in the world. It seemed that coupling this blueprint with a subsea storage tank could be the solution to the FPSO problem, an idea which would spark the formation of SeaCaptaur.

While the spar buoy and tank design has been proposed previously for Small Pools developments, Begley and Roberts believe that their system overcomes the key challenges which have so far limited progress.

However, the conflicting motion on the surface between the spar buoy and a vessel deploying a gangway made designing that system a little trickier. “The reason it didn’t work initially was that we couldn’t moderate the spar buoy motions in such a way that we could reliably deploy a gangway from a DP vessel,” Roberts says, essentially preventing any personnel from safely reaching the spar buoy to carry out installation, maintenance and the offloading of oil. It was here that SeaCaptaur turned to an innovation from the renewables industry.

“The gangways used by the offshore wind farm industry are the key to being able to put people safely on these buoys. These are basically a 14m-in, 21m-out gangway, which gives you a 7m range before you’re in trouble,”

InnovOil InnovOil

Annual 2016

page 47

THE BEST OF 2016

Oil off-take is proposed by a small tanker on Voith Schneider propulsion.

he explains. These wind farm systems have a significant wave height limit of 2.5m, which in the central North Sea represents a 95% mid-summer transferability, reducing to 40% mid-winter. Operating under such arrangements with the close-in reference target (the spar buoy) moving presents many challenges for the DP close-in reference systems, such as fan beam and USBL. The tanker vessel can then deliver oil to locations up to 600 nautical miles (1,100 km) from the spar buoy, with the best outcome being a refinery, eliminating a third-party facility tariff through charge, and a lifting charge from that third-party facility, possibly a net saving up to US$15.0 per bbl.

The challenges of marketing small, possibly mixed, source crude lots have been discussed with a number of oil traders. Some view these with enthusiasm; others not so.

The buoy is monolithic to the subsea connection joint on the tank, which aids stability by limiting motion. “That also solves a range of other problems at the same time,” Roberts adds. “The underslung architecture required between an FPSO and the seabed is inside the spar buoy leg. It then becomes a plug and play interconnect”.

SeaCaptaur estimates an approximate ex-builder CAPEX for a 100m deep spar buoy of around US$75 million, with the “offshore installation time with a large DSV estimated to be 36 hours,” he explains.

Tanks and tugs With the exception of the gangway, Roberts is quick to point out that very little in the SeaCaptaur system is new to the industry.

Even the subsea tank design is relatively commonplace, although it has seen some additional innovation. The SeaCaptaur tank is designed to be a double-hulled, MARPOLcompliant tank, assuming with time that regulators will require subsea tanks to be built to that standard.

That lowers costs too. “The double hull allows the tank to be deployed and recovered using a heavy Anchor Handling Tug (AHT) rather than a derrick barge,” he adds. “A barge in the UK North Sea is about GBP1 million [US$1.3 million] per day, whereas an AHT is around GBP 95,000-100,000 [US$122,000130,000] per day. It’s an order of magnitude difference.”

The ability to use an AHT also opens up a wider installation schedule. A limited

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number of installation vessels and a restricted weather window keeps operating costs (and project risk) high with similar projects (Roberts cites the tank installation duration at the Solan field, offshore West Shetland, as a cautionary tale). “We set the SeaCaptaur subsea tank basically as a deep-water mooring with manipulation of the buoyancy of the tank so that a vessel such as a Maersk L-class can use its winch… All we have to do is keep the tank’s submerged weight in the region of 300 tonnes and the vessel should have no problem getting it down,” he continues.

Moreover, the tank is reusable. Once its production life has ended, it can be recovered and dry-docked before being redeployed, all of which helps to lower the lifetime cost.

Although none have yet been built for a full SeaCaptaur system, the company calculates the ex-builder CAPEX of a 65,000 bbl uninsulated tank to be approximately US$28 million.

Well planned Much of the rest of the system’s efficacy comes down to size, planning and placement. The notional operating limit of 300m substantially captures the world’s opportunity set. Small is the key to staying within budget. Any form of gas compression is not possible owing to confined space safety. Staying small is also the key to the thermal management of waxy and high pour point crudes. Emulsions are unwelcome, but manageable. The 10,000 bpd production limit has demonstrated itself in many case studies not to be an unfavourable upper bound, and a better economic outcome is achieved by limiting early production rates,

and extending production life, rather that up-sizing.

The opportunity roll-out in a specific setting such as UKCS becomes “a mathematical theory issue”, Roberts notes.

Although the most economical way to drain most pools would be with a single well, the latter’s performance risks drive the need for a second well, unfavourably affecting UTC. However, the SeaCaptaur system can be placed via tie-backs to nearby (say 5 km) locations, which could also mitigate the single-well dependency risk. Each system would be capable of handling three tiebacks.

Roberts believes that a clustered approach makes much greater sense – a strategy highlighted by the UK’s Wood Report, and enforced by regulators in countries such as Malaysia. A recent study commissioned by NSRI and undertaken by undergraduates at Robert Gordon University is the first step in building the mathematical foundations of understanding the clusters conundrum and the Wood Report MER (Maximise Economic Recovery) objectives. Systems such as SeaCaptaur cannot be viewed as single-project, unitary deployment systems. Serialisation and clustering have to enter the lexicon of Small Pools to take new projects’ UTC from US$60 per bbl down to US$25 per bbl.

Clustering requires some innovation too, albeit at a policy level. Roberts believes that in most markets, the current business and regulatory model is unsuitable for the types of developments which are needed. “What’s going to have to happen is to aggregate a good field and four or five Small Pools, to mix the high hanging and low hanging fruit NEWSBASE

into economic opportunity sets. The grid map approach doesn’t work in the next phase; instead you put them together as a cluster or a set and offer them to the market.”

New forms of finance will also need consideration if these pools are to be tapped.

“We need to look at the whole financing arrangement – we need to be able to lease these facilities, not capitalise them,” he says.

“When we do the numbers it works for everyone: the operators make money and the government collects taxes; on a capitalised basis there are no winners.”

Fortunately, interest in Roberts and Begley’s technology has been promising. At present, the SeaCaptaur system is under assessment by INTECSEA, a process which will see the group “independently verify the proof of concept,” Roberts says. Between that verification, UK cluster analyses, meeting regulators and looking for companies willing to take on the technology, SeaCaptaur has plenty to contend with. In addition to all of that, the SeaCaptaur Team will soon be on the road fundraising to support the completion of the development phase plus the build and deployment of SC1.

Despite the industry’s conservative outlook, the concept has found favour with groups like ITF and the NSRI. With the right support, the SeaCaptaur system could well prove transformative for Small Pools worldwide. Begley and Roberts may have saved those E&P juniors after all. n Contact: Alan Roberts

Tel: +61 (04) 1234 7324 Email: admin@seacaptaur.com.au Web: www.seacaptaur.com.au

page 50

InnovOil

What next …?

To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections If you’d like to discuss a new challenge for Bronswerk Heat Transfer engineers, contact Femke Schaefer on: +31 (33) 24 72 500, or email femke@bronswerk.com Contact: Susan Ganz - Schlumberger. Email: Sganz1@slb.com, Web: www.slb.com To learn more about GustoMSC’s Scyllax drillship, and how it could change the economics of deepwater drilling, contact Tessa Vleugels on +31 10 2883 000, or via tessa.vleugels@gustomsc.com The SeaCaptaur System could unlock billions of barrels in so-called “small pools” oil deposits across the world. To learn more about the technology, contact Alan Roberts on +61 (04) 1234 7324 or via admin@seacaptaur.com.au We will be watching out for the progress of Well-SENSE Technology’s revolutionary FLI concept in 2017. To speak with inventor Dan Purkis, call +44 (0)1224 937 600 or email dpurkis@well-sense.co.uk Interwell’s thermite P&A concept proved to be one of the most exciting innovations we covered this year. For more information on the solution, please speak with Terje Hauan, Commercial Manager, P&A on +47 41 44 77 22 or at teha@interwell.com Professor Maroto-Valer of Heriot-Watt University is pioneering the development of “smart rocks” – 3D-printed core replicas with embedded sensors which could unlock new detail on pore-scale flow models. To learn more about her research, contact +44 (0)131 451 8028 or m.maroto-valer@hw.ac.uk If TSC Inspection ACFM® technique, or its MagCrawler ROV could help the integrity of your subsea assets, contact David Parramore on +44 (0)1908 317 444 or email info@tscis.com EC-OG has big plans for the Subsea Power Hub next year. For more detail, speak with Graceann Robertson on +44 (0)1224 933 301 or contact info@ec-og.com For more on Visuray’s x-ray imaging techniques, contact Angeline Tse at angeline.tse@visuray.com

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InnovOil, from the NewsBase group, is a technology-driven, monthly magazine which aims Andy Hill, Group Marketing Manager to provide a platform for innovators and engineers to share to share their ideas and expertise.

IPU Group Our publication remains a trusted, solicited information source for technology news across the complete spectrum of the upstream, midstream and downtream oil and gas sectors.

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