InnovOil Issue 59, December 2017

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Bringing you the latest innovations in exploration, production and refining Issue 59

December 2017

AN INSPECTOR CRAWLS The latest asset integrity technologies Page 13

OUT OF TONER

3D printing marinegrade steel Page 8

NEW WORLD RECORD

Sakhalin and the world’s longest well Page 7

Main Congress: 27 – 28 February 2018 Pre-Congress Workshops: 26 February 2018 Post-Congress Workshops: 1 March 2018 Venue: ILEC Conference Centre, London

ENABLING MARKET RECOVERY

BY OVERCOMING THE STORM STREAMLINING processes for enhanced project conceptualisation, execution & deployment

TRANSFORMING FPSO operations For increased productivity And reduced Costs

RE-DEFINING Project Execution & Operations

MAXIMISING value from, and for, FPSO projects

OVERCOMING the financing bottleneck to push FPSO projects forward

KEYNOTE SPEAKERS INCLUDE:

Keith Williams Project General Manager, Western Isles Development Dana Petroleum

Stuart Wheaton DirectorUK Business Head Premier Oil

Conrad de Souza Specialist Structural Integrity Inspector UK Health & Safety Executive

fpsoeuropecongress.iqpc.sg

Eirik Barclay Chief Executive Officer Yinson Production

Peter Burger Vice President, Technology Bluewater

InnovOil

December 2017

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Inside Contacts: Media Director Ryan Stevenson ryans@newsbase.com

A note from the Editor

5

Media Sales

Fitter filters

6

Charles Villiers charlesv@newsbase.com

World’s longest well

7

Kevin John kevinj@newsbase.com

Making the grade

8

Editor Andrew Dykes andrewd@newsbase.com

Tech Radar

Sub-nanoscale graphene filtration

Sakhalin-1 drills 15km

3D printing with marine-grade steel

Outside the world of oil and gas

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ASSET INTEGRITY 13-21 Autonomy with Avitas

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Tracerco’s Discovery™

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Stabilising production

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The Russian shelf

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Catcher field milestone

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Catalytic conversion

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Automating the inspection process

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World’s only proven subsea CT scanner

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

Well-Centric’s range of specialist well clamps

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Gazprom unveils revised strateg ations Bringing you the latest innov

in exploration, production

and refining December 2017

Issue 59

Launch of production by the end of year

AN INSPEC TOR CRAWLS

The latest asset integrity technologies Page 13

10

Propylene process performance from Dow Chemical

R OUT OF TONE marine-

3D printing grade steel

Valemon 30

Page 8

NEW WORLD RECORD

Statoil’s automated rig control room

Sakhalin and the world’s longest well Page 7

News in brief

32

Contacts 39 NEWSBASE

Europe’s largest annual Subsea Exhibition and Conference Aberdeen Exhibition and Conference Centre (AECC) 07-09 February 2018

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December 2017

InnovOil

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A note from the Editor ALONGSIDE automation, digitalisation and the blockchain, the potential impact of machine learning is another hot technology topic du jour.

It is easy to be dismissive of the potential of what is essentially computer-managed pattern recognition; it is less easy to be dismissive of its results. These were made clear to InnovOil this month in discussions with Avitas Systems, a start-up founded recently within GE, with the aim of revolutionising the inspection market.

With our focus this month on asset integrity, and the solutions that may aid operators in assuring it, InnovOil was particularly interested in where inspection technologies – particularly the UAVs, AUVs and crawlers which make up Avitas’ offering – will lead the industry over the next few years. What in fact was surprising is where they are now.

While for many operators the novelty of using UAV asset inspection techniques may not yet have worn off, Avitas is already confident that UAVs are capable of flying themselves (guided by a highly accurate mission plan, of course). Using software and sensor packages available today, the company’s aim is to automate the inspection process completely, from inspection to reporting – and that has profound implications from an asset integrity perspective.

Using machine learning, the data gathered

from these automated inspections can be very rapidly assessed, down to an astounding level of detail. Corrosion can be pinpointed and its severity identified down to the level of individual bolts, all within a matter of minutes.

With time and resources freed up, operators can also design more proactive maintenance plans. Rather than routine arbitrary inspections, smarter management will see resources applied to those assets which require attention, and less to those that do not. Moreover, the data collected on those assets will (ideally) be preserved and can be assessed over time, meaning owners build up a much better idea of their integrity and performance over their lifetime – all aided by machine learning (which too becomes more accurate the more patterns it sees).

The point here is that the solutions to many challenges are already here. It will now take leadership from operators and service providers to employ them if the industry is ever to realise its promised savings and efficiencies.

And plenty of solutions there are in this issue: from other asset integrity technologies like well clamps and subsea CT scanning, to the drilling of the world’s longest well in Russia, to 3D-printed marine steel and remote platform control rooms, the future is already upon us.

We are pleased to present the December issue of InnovOil.

Andrew Dykes Editor

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InnovOil

December 2017

New perspectives on twodimensional filtration Researchers from the University of Manchester have successfully created sub-nanoscale filtration devices using graphene

G

RAPHENE is transforming the way we approach a number of key materials problems, but one of its lesser-known qualities is permeability.

Back in 2012, researchers at the University of Manchester discovered that graphene oxide –a sheet made from a single layer of carbon atoms – was impermeable to gases and liquids it tested, with the exception of water.

Studies at the University’s National Graphene Institute (NGI) proved that these properties could be used in filtration to remove small nanoparticles, organic molecules and even large salts from water. Further research published in April 2017 expanded on this, and managed to control the material’s tendency to swell in water, making it suitable for sieving out the common salts used in desalination.

In October, that was taken a step further, as NGI staff succeeded in fabricating a device with the smallest possible man-made holes.

At several angstroms (0.1 nanometres) in size, it has allowed closer study of how ions pass through the material.

The slits are made from graphene, hexagonal boron nitride (hBN) and molybdenum disulphide (MoS2) and, in fact, allow ions with diameters larger than the size of the slit to permeate. The team says this will increase understanding of how similar scale biological filters such as aquaporins (or water channels) work and could help the development of better filters for desalination.

Changing the channel Scientists have tried for years to create water channels capable of filtering small ions or individual water molecules. Yet those fabricated with traditional materials remain limited as a result of the intrinsic roughness of a material’s surface, whose spaces are typically at least ten times bigger than the diameter of smaller ions.

In this case the NGI team, led by Sir Andre Geim, made atomically flat, chemically inert slits at the sub-nanometre scale. These were constructed from two 100-nm slabs of graphite, in between which were placed 2D atomic crystals of bilayer graphene and monolayer MoS2. These crystals were placed at each edge of the graphite slabs, with another slab placed on top, producing a gap between with a height equal to the thickness of the central layer.

Geim explained: “It’s like taking a book, placing two matchsticks on each of its edges and then putting another book on top. This creates a gap between the books’ surfaces with the height of the gap being equal to the matches’ thickness. In our case, the books are the atomically flat graphite crystals and the matchsticks the graphene or MoS2 monolayers.”

The device is held together by van der Waals forces – the attraction of intermolecular forces between molecules – and each slit is roughly the same size as an aquaporin. The team says this is as small as the slits can get, given that any with thinner space would be unstable and collapse.

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When a voltage is run across the device while immersed in an ionic solution, ions can flow through the slits, essentially creating an electric current. The team measured ionic conductivity as they passed through chloride solutions via the slits and found that ions could move through them as expected under an applied electric field.

“When we looked more carefully, we found that bigger ions moved through more slowly than smaller ones like potassium chloride,” added post-doctoral researcher Dr Gopi Kalon, who headed the experiments.

The first author of the paper, which was published last month in Science, Dr Ali Esfandiar, continued: “The classical viewpoint is that ions with a diameter larger than the slit size cannot permeate, but our results show that this explanation is too simplistic. Ions in fact behave like soft tennis balls rather than hard billiard ones, and large ions can still pass – either by distorting their water shells or maybe shedding them altogether.”

The phenomenon reported in their paper is expected to enable new advances in desalination using molecular size exclusion, and the team believes their work could be a key step in the creation of high-flux water desalination membranes. n Contact: Ben Robinson, Graphene

Communications and Marketing Officer Email: ben.robinson@manchester.ac.uk Web: www.graphene.manchester.ac.uk

December 2017

InnovOil

Sakhalin-1 completes world’s longest well

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The ExxonMobildeveloped Fast Drill technology was used to drill the 15,000m well

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HE Rosneft-led consortium operating the Sakhalin-1 project in the Russian Far East has completed the world’s longest oil well.

In a statement on November 16, Rosneft said the well, which measured 15,000 metres, had been sunk at the Orlan platform on the Chayvo oilfield in the Sea of Okhotsk.

The state-owned oil producer noted that the well had a directional drilling index of 8.0 and a stepout of 14,129 metres.

Including the latest record, Sakhalin-1 has been responsible for drilling nine of the world’s 10 longest wells, five of which have been completed since 2013. In mid-2013, the consortium finished work on the Z-43 and Z-42 wells, measuring 12,450 and 12,700 metres respectively. It also completed the 13,000-metre Z-40 well in 2014, followed by the 13,500-metre O-14 well in 2015.

According to Rosneft, these wells have been drilled using an extended reach technology known as “Fast Drill”, developed

by US major ExxonMobil, a partner in the Sakhalin-1 consortium.

According to information from ExxonMobil, Fast Drill uses drilling physics models together with structured well planning and design to identify drilling parameters and increase performance. A Drilling Advisory System automates the process in real time on the rig floor, and as of February 2017 had improved at nine fields.

The supermajor says that its drilling rate has improved more than 80% since the process was adopted more than a decade ago.

“This technology combined high quality modelling of physical parameters of drilling with a structured approach to well design,” Rosneft said. “Extended reach drilling reduces costs of construction of additional offshore structures, pipelines and other field infrastructure facilities and it also mitigates

environmental impact due to smaller drilling and production footprint.”

Chayvo is located some 6 km off the coast of Sakhalin Island in waters depths of between 14 and 30 metres. The field was discovered in 1979 and began flowing oil in 2005. It is one of three offshore oilfields to have been brought into production by the Sakhalin-1 consortium, which comprises Exxon subsidiary Exxon Neftegas (30%), Japan’s SODECO (30%), Rosneft (20%) and India’s ONGC Videsh (OVL) (20%).

The other two fields – Odoptu and Arkutun-Dagi – came online in 2010 and 2015 respectively. Sakhalin-1 also controls the non-producing Lebedinskoye field, where development drilling began in May last year.

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The consortium produced a total of 9 million tonnes (180,000 bpd) of crude oil and condensate in 2016, versus 167,000 bpd in the previous year. Exxon Neftegas has said it hopes to maintain output at the current level for as long as possible.

In September, the Russian Finance Ministry said it had reached an amicable agreement with Exxon in a lawsuit over tax payments related to the Sakhalin-1 project. The US major filed for arbitration in Stockholm in 2015, claiming it had overpaid US$500 million in profit taxes on its stake in the venture. As part of the settlement, Exxon was reportedly offered involvement in an oilfield project owned by Rosneft in Western Siberia, according to Russia’s Kommersant newspaper. n

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December 2017

3D-printed marine steel makes the grade Researchers from several US universities have pioneered a project to 3D print marine-grade steel, creating a material that is stronger and more flexible

T

HE corrosive effects of saltwater naturally call for the careful choice of materials in offshore projects.

In the case of stainless steels, specific “marine-grade” alloys are used, typically characterised by higher levels of molybdenum to protect against the harsh environment.

These marine-grade steels also have high ductility – the ability to bend without breaking under stress – meaning they are a preferred choice in oil pipelines, welding, chemical equipment and other applications.

Yet while it is possible to strengthen these marine grade steels for added protection, this usually reduces ductility.

A new alternative approach has been suggested by a consortium of US universities. By 3D-printing a common marine-grade alloy – a low-carbon grade

known as 316L – the group has succeeded in producing steel which is both stronger and more flexible than its conventional form. The team, led by Lawrence Livermore National Laboratory (LLNL), with the aid of Ames National Laboratory, Georgia Tech University and Oregon State University), believes the breakthrough could aid applications in aerospace, automotive and oil and gas, and recently published its work in Nature Materials.

LLNL materials scientist and lead author Morris Wang noted: “We were able to 3D-print real components in the lab with 316L stainless steel, and the material’s performance was actually better than those made with the traditional approach.

That’s really a big jump. It makes additive manufacturing very attractive and fills a major gap.”

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Just around the bend Achieving this meant first adapting the printing process for this particular alloy.

Until now, the melting of metal powders during the additive manufacturing process – in this case powder bed fusion (PBF), which uses either a laser or electron beam to melt and fuse material powder together – resulted in an overly porous material which could degrade and fracture easily.

This had been regarded as a serious drawback to using this technology. To overcome this, the team experimented and modelled the material as part of a density optimisation process, and also examined the effects of manipulating the underlying microstructure of the metals.

Over several years, the group built up a more detailed understanding across the campuses. Ames Lab used X-ray diffraction

December 2017

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LLNL materials scientist Joe McKeown looks on as postdoc researcher Thomas Voisin examines a sample of 3D printed stainless steel.

(Photos by Kate Hunts/LLNL)

to understand material performance, Georgia Tech used computer modelling to understand the materials’ strength and ductility, and Oregon State performed characterisation and composition analysis.

“This microstructure we developed breaks the traditional strength-ductility trade-off barrier,” Wang explained. “For steel, you want to make it stronger, but you lose ductility essentially; you can’t have both.

But with 3D printing, we’re able to move this boundary beyond the current trade-off.”

Using two different laser PBF machines, the researchers printed thin plates of 316L stainless steel for mechanical testing.

Their laser melting technique produced “hierarchical cell-like structures” that could be tweaked to alter the mechanical properties of the final material.

Not only is the material stronger, but,

as Wang told InnovOil via email, “There is potential evidence from other groups suggesting that 3D printed stainless steels actually have better corrosion resistance.”

LLNL’s Alex Hamza added: “When you additively manufacture 316L it creates an interesting grain structure, sort of like a stained-glass window. vThe grains are not very small, but the cellular structures and other defects inside the grains that are commonly seen in welding seem to be controlling the properties. This was the discovery. We didn’t set out to make something better than traditional manufacturing; it just worked out that way.”

“Deformation of metals is mainly controlled by how nanoscale defects move and interact in the microstructure,” added LLNL postdoctoral researcher Thomas NEWSBASE

Voisin, another key contributor to the paper.

“Interestingly, we found that this cellular structure acts [like] a filter, allowing some defects to move freely and thus provide the necessary ductility while blocking some others to provide the strength. Observing these mechanisms and understanding their complexity now allows us to think of new ways to control the mechanical properties of these 3D-printed materials.”

For the team, the goal now is to apply similar methodologies and computer modelling to predict the performance and composition of other stainless steels and lighter-weight alloys which may be brittle or crack prone. n Contact:: Jeremy Thomas Email: thomas244@llnl.gov Web: www.llnl.gov

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InnovOil

On the radar

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

A better look at wetter Wetting – the description of how liquid spreads on a surface – is a vital area of study for manufacturers of paints, coatings and other products. They will likely be buoyed by the news that Aalto University researchers have developed a new measurement technique dubbed “Scanning Droplet Adhesion Microscopy” (SDAM) to understand and characterise the wetting properties of water-averse or “superhydrophobic” materials.

Claimed to be 1,000 times more precise than current techniques, the microscope can measure tiny surface features and flaws down to the microscale. Existing instruments for measuring droplet adhesion forces only detect forces down to a micronewton level, but SDAM can detect forces in nanonewtons.

“Our novel microscope will promote the understanding of how wetting emerges from surface microstructures. The measuring instrument can also detect microscopic defects of the surface, which could allow coating manufacturers to control the quality of materials. Defects in self-cleaning, anti-icing, anti-fogging, anti-corrosion or

anti-biofouling products can impeach the functional integrity of the whole surface,” Professor Robin Ras from Aalto University School of Science commented.

“We have used a droplet of water to measure the water-repellent properties of a surface by recording the very tiny nanonewton force when the droplet touches the surface and when it separates from the surface. By measuring on many locations with micrometre spacing between the measurement points, we can construct a twodimensional image of the surface’s repellency, called a wetting map,” added School of Electrical Engineering Professor Quan Zhou.

The method also offers an alternative to contact angle measurement, the previous standard method for wettability calculation, but one which is prone to inaccuracy on superhydrophobic surfaces. SDAM can also detect wetting properties of microscopic functional features that were previously very hard to measure. Those microscopic features are important in many biochips, chemical sensors and microelectromechanical components and systems. n NEWSBASE

December 2017

Plastic people MIT researchers have used pulverised irradiated plastic to strengthen concrete, in a process which could enable better flexibility when using the material in construction – reducing carbon emissions. The process uses discarded plastic bottles which would otherwise have ended up in landfill.

Initially, the use of flakes of plastic – in this case polyethylene terephthalate – actually weakened concrete in experiments. However, the team of undergraduates found that by exposing these flakes to low and high doses of radiation and then crushing them into a powder, the resulting cement mixture (together with common additives fly ash and silica) produced concrete that was up to 15% stronger.

Using X-ray diffraction, backscattered electron microscopy and X-ray microtomography, they discovered that the irradiated plastic produced more cross-linked, crystalline structures within the mixture, making it denser, less porous and therefore stronger.

“At a nano-level, this irradiated plastic affects the crystallinity of concrete,” said one of the students, Kunal Kupwade-Patil. “The irradiated plastic has some reactivity, and when it mixes with Portland cement and fly ash, all three together give the magic formula, and you get stronger concrete.”

“We have observed that within the parameters of our test programme, the higher the irradiated dose, the higher the strength of concrete, so further research is needed to tailor the mixture and optimise the process with irradiation for the most effective results,” Kupwade-Patil added. “The method has the potential to achieve sustainable solutions with improved performance for both structural and non-structural applications.”

The team included Carolyn Schaefer and MIT senior Michael Ortega (who began the research as a class project), as well as research scientist Kunal Kupwade-Patil, Department of Nuclear Science and Engineering Assistant Professor Michael Short, Associate Professor Anne White, the Department of Civil and Environmental Engineering Professor Oral Büyüköztürk and Carmen Soriano of Argonne National Laboratory. n

December 2017

Iceberg ahoy Canada’s Centre for Cold Ocean Resource Engineering (C-CORE) and Norwegian NOC Statoil have launched a competition to crowdsource better techniques for identifying icebergs based on satellite imaging.

The Statoil/C-CORE Iceberg Classifier Challenge was posted on Google-backed data problems website Kaggle, and offers a price of up to US$25,000 to the winning systems, capable of identifying potentially threatening icebergs drifting towards the Grand Banks area in Newfoundland.

While current satellite radar detection systems are functional, they can sometimes struggle to tell the difference between ships and icebergs; the goal here is to create a smarter algorithm which can. C-CORE has thus provided a large database of images for interested scientists to use in their pursuit of an automated detection system.

“We’ve got a database of 5,000 targets that we’ve uploaded to this website and the competition, which has prize money of US$50,000, will give people the incentive to look very closely at our database,” said Desmond Power, C-CORE’s vice president

No foul Researchers at the University of Pennsylvania’s School of Engineering and Applied Science have devised a new method of making filtration membranes which could help prevent biofouling. Their method allows them to add in a host of new capabilities via functional nanoparticles that adhere to the surface of the mesh.

In a paper recently published in the journal Nature Communications, the team described their method, which allows for membranes to be made from a range of polymers and nanoparticles. Their “antifouling” properties would be useful in applications such as filtering drinking water, but could also be used to separate oil compounds and pollutants from fracking wastewater.

InnovOil

of remote sensing, was quoted by CBC News as saying.

“To keep operations safe and efficient, Statoil is interested in getting a fresh new perspective on how to use machine learning to more accurately detect and discriminate against threatening icebergs as early as possible,” the post added.

As of late November, there are already

It may even be possible to use other nanoparticles to catalyse reactions with the contaminants, destroying them or even converting them into something useful.

The method uses a liquid mixture known as a “bicontinuous interfacially jammed emulsion gel,” or “bijel.” Unlike emulsions, which consist of isolated droplets, the oil and water phases of bijels are intertwined and fully connected. Nanoparticles used in this mixture then move to the interface between the oil and water.

Tests were performed using doped silica nanoparticles, made into tubes and altered to offer different functions – in this case antifouling properties. The team demonstrated the filtering and antifouling using water containing gold nanoparticles of various sizes.

The study was led by Penn Engineering Department of Chemical and Biomolecular NEWSBASE

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over 1,500 teams with just under two months to go until the application deadline of January 16, 2018, and a final submission deadline of January 23.

The groups are hopeful that these teams can generate interesting solutions. “It’s an interesting thing to try out for them, I guess,” Power told CBC. “Icebergs are cool, satellite images are cool.” n

Engineering Professor Daeyeon Lee, and Penn Engineering’s Deputy Dean for Research and Richer & Elizabeth Goodwin Professor of Chemical and Biomolecular Engineering Kathleen Stebe, as well as Martin F. Haase, an assistant professor at Rowan University who developed the technology as a postdoctoral researcher in the labs of Stebe and Lee. Harim Jeon, Noah Hough and Jong Hak Kim also contributed to the study.

“In our experiment, we were able to filter out very small gold nanoparticles, in sizes equivalent to viruses,” said Lee. “The tube shape also works well in large-scale implementation of these filter membranes.

Because they have large surface-area-tovolume ratios and don’t get clogged, we can draw in fluid from the sides and suck it out from the end, allowing for continuous filtration,” explained Lee. n

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ASSET INTEGRITY

December 2017

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SPECIAL SUPPLEMENT Pages 13-21

SUB-CT

Exploring Tracerco’s Discovery pipeline scanner Page 18

CLAMPING, YOUR STYLE

Well stabilisation from Well-Centric Page 20

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InnovOil

December 2017

ASSET INTEGRITY

Machine learning makes for more intelligent inspections Andrew Dykes discusses the future of autonomy and asset integrity with Brad Tomer of Avitas Systems

R

OVS, UAVs and crawlers are already the backbone of the modern asset inspection fleet, but they are only as useful as their human operators.

In many cases, data gathered digitally must still be processed and reported on manually, accounting for considerable time and resources even after the inspection itself is complete. However, one GE venture company intends to alter the industry’s expectations radically.

“We’re a company that is trying to digitise

the inspection market from end to end,” Avitas Systems’ VP of operations Brad Tomer told InnovOil. “We do this on three levels: we’re automating the collection of data through robotics and permanent sensors; we fuse various data sources together and use data analytics together with a deep learning platform for automated defect recognition, and finally, we have automated reporting and workflow so maintenance can be initiated right away.”

The inspection market itself is worth some NEWSBASE

US$40 billion a year, Tomer said, of which oil and gas alone makes up about US$10 billion.

Avitas Systems was conceived as a start-up within GE, with the aim of capitalising on that sizable opportunity. Using the “GE Store” concept – a corporate philosophy which encourages the transfer of technology and knowledge across the company’s many units – Avitas Systems combines some of the most cutting-edge technologies available from the company’s various units, including GE Global Research Center.

December 2017

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ASSET INTEGRITY

Avitas Systems flare stack inspection

Bringing together data analytics, robotics and artificial intelligence expertise from aerospace, transportation, renewables and oil and gas, the goal is to fully automate the inspection process, with the world’s “first endto-end solution.” Doing so, Tomer said, could reduce the costs of inspection by up to 25%.

An inspector crawls The inspection equipment and routines used by Avitas Systems are reassuringly familiar. Manned inspections teams are

dispatched to survey assets in much the same way, using the company’s technicians and agreed mission plans. The group works with providers of robotic technology to employ state-of-the-art underwater vehicles (remote and autonomous), as well as aerial drones (UAVs), and magnetic/tracked crawlers.

Sensor packages include inspection staples like LiDAR, infrared/HD cameras and laser measurement devices, among others.

Tomer instead explained that the company’s defining capabilities were its NEWSBASE

automation and artificial intelligence systems: “The differentiation of our autonomy system is that it not only controls the flight and mission of the drone but it controls the sensors themselves. It’s a full autonomy package that will allow us to take repeatable measurements from the same distance, location and angle every time.”

This capability is what helps Avitas Systems gain an edge over traditional manual inspection routines. The accuracy of these machine-led measurements means the quality

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December 2017

ASSET INTEGRITY Right: AI Workbench Far right: 3-D model

of data gathered is unsurpassed, and can be used to track the life of an asset in more detail than ever before. Tomer added: “Once we have a mission plan developed we can repeat it over and over again. That allows us to see changes over time, and our deep learning system can see these patterns, what is changing and where you should place your attention.”

Autonomous robotic inspection offers a number of intrinsic benefits, which InnovOil has covered widely in the past.

The ability to inspect assets while they remain in production means no lost revenue, and potential safety risks to personnel are reduced with less need for rope access. But the ability to source better data quality is also important – one UAV can perform multiple runs with different sensor packages, allowing operators a full suite of datasets from infrared imaging to point-cloud modelling, in a substantially reduced amount of time. This advantage only grows in the data-processing stage.

The GE Predix platform, on which the system is built, can analyse inspection data and identify defects automatically, and can also integrate other disparate external data sources, such as weather, to recommend future inspection and maintenance schedules.

Data are then made available via a secure online platform, ensuring that customers have access to – and ownership of – their asset data.

The implications of AI and machine learning in this environment are, even for the technically minded, impressive. By training the AI to recognise specific components – achieved by showing it thousands of images of, say, bolts – the resulting neural network can identify the location and integrity of those components in data gathered from new inspections, and with a remarkable degree of detail.

“If you want to find all the bolts on a flare stack, for example, you can do that,” Tomer explained. “We can then run our corrosion [monitoring] system to identify how severe corrosion is, to six different levels of severity.

You can do that today, and then next time you inspect the asset you can see the change in severity and act accordingly – and the system does all that automatically.”

The more images and data the system gathers, the more accurate it becomes. He noted that the same flare stack bolt dataset was then used to train the system to identify bolts and corrosion on a set of transmission towers. And unlike manual inspections, that learning process is compressed into a tiny window of time – Tomer said processing for the transmission towers took just ten minutes once the data were collected.

“That’s the key. Some people are doing robotic collection of data and then a lot of manual interrogation of that data,” he continued. “We’re trying to disrupt the inspection process from end to end, to truly digitise the process for inspection as a service.”

Awaken the Kraken As these capabilities grow, Avitas Systems has incorporated more technologies into NEWSBASE

the platform. In September it announced a partnership with chipmaker NVIDIA to enhance its AI capability, and even more recently signed an agreement with subsea technology vendor Kraken Robotics. This will see the latter’s SeaVision sensor adapted as a payload for autonomous underwater vehicles (AUVs).

SeaVision is a highly accurate 3D laser scanning system, capable of producing very high-resolution scans in full colour.

Borrowing techniques from the company’s Synthetic Aperture Sonar system, SeaVision uses a twin-scanner configuration to produce a 1.2 million point scan in four seconds, either from a stationary position, or in motion. Processing the data enables the creation of a detailed 3D model of an asset for existing autonomous systems from Avitas Systems.

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ASSET INTEGRITY

“3D modelling with SeaVision is faster and higher resolution than most systems on the market today,” added Tomer. “We’re going to mount the laser system on underwater vehicles for 3D modelling of subsea assets.

The combination of their laser system and our autonomous system allows us to inspect the same points on assets, identify defects and detect changes over time,” he said.

The result is an even more detailed picture of subsea assets over time, and faster notification in the event of a failure.

Deeper understanding Avitas Systems has already had “an overwhelming response” to the technology from operators, Tomer noted, though he admitted to a familiar frustration that the contracting structure of many international oil companies (IOCs) means it can be uphill

battle getting new services like this approved.

Nevertheless, with the level of detail and time saving on offer, it seems that it will not take long before the autonomous inspection model becomes an industry standard.

With autonomous systems now capable of handling much of the legwork of asset inspections, Avitas Systems will focus on improving efficiency even more in future.

One avenue will be to devise payloads capable of gathering multiple datasets in a single run – simultaneous capture of infrared and RGB images, for example. Tomer said that the company was already working on that capability, and that the team was just a few months away from being able to undertake a mission with multiple sensors in one payload.

In addition to larger and more complex payloads, some improvements will be enabled NEWSBASE

by regulatory changes. Few environments currently allow UAV operations beyond line of sight (LOS), for example. That makes inspecting linear assets such as pipelines and transmission lines slower, Tomer said, largely because of the difficulty in conducting long-distance scans while maintaining visual contact. Yet as these technologies becomes more accepted, autonomous systems such as Avitas Systems will likely be some of the first into the breach.

“We’re taking a systems-by-systems approach. In the next five years, we will be working on things that will make us even more efficient than today. As our deep learning system learns more, and as our robotic capabilities extend to untethered and beyond line of sight, we will become more efficient and accurate,” he added.

What is clear, however, is that these technologies are already reshaping how the industry approaches challenges associated with asset integrity. Rather than cyclical programmes of arbitrary inspection and maintenance, Avitas Systems offers a more intelligent and predictive solution, informed by learning gathered from thousands of other assets. “Today’s inspections are time-based, and they are based on rules of thumb. Some are too late, and some are too soon,” he explained. “But five years from now, with all the data we can bring in, I think we’ll be able to predict when you need to do those inspections – so you can do more frequent inspections on high-risk areas and less frequent on the low-risk areas, and tailor your strategy to the asset itself.”

The next five years look very exciting indeed. n Contact: Dominique Mann, Communications Manager Tel (US): +1 202-316-7103 Email: dominique.mann@ge.com

Jeff Plaskon, Head of Solution Sales Tel (US): +1 216-338-2396 Email: Jeffrey.Plaskon@ge.com Web: www.avitas-systems.com

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December 2017

ASSET INTEGRITY

Seeing it through with Tracerco’s Discovery™ Discovery™ is the world’s only field proven subsea CT scanner, and offers unparalleled information into pipeline integrity and flow assurance issues, without the need to remove coatings

A

S assets age, integrity issues tend to be of greater concern to operators.

Ensuring that subsea installations are free from corrosion and/or flow assurance issues requires tight inspection and maintenance regimes, most of which require considerable time and money, and often lost production.

Subsea pipelines are no exception and can present an even greater challenge where lines are unpiggable, or are protected with coatings that must be removed and then replaced to ensure accurate measurements.

In cases where traditional inspections cannot provide accurate information, operators may even be forced to estimate or model the pipeline, making key decisions without data that reflect the actual condition of the asset.

Tracerco specialises in providing technologies for real-time condition monitoring of subsea assets. One of its flagship innovations – Discovery™ – is the world’s only subsea computed tomography (CT) scanner, and offers a distinctive solution to the challenges of pipeline inspection.

First brought to market in 2015, Discovery remains unique in its use of CT technology to enable non-intrusive pipeline inspections. The system is the only technology able to scan through any type of protective coating and develop a complete tomographic image of pipe wall thickness, as well as the contents of the pipe, including waxes, asphaltenes, scales, hydrates, sand and lost pigs.

This technique also means that the system can be used on a variety of

installations – including pipe-in-pipe, pipe bundles, caissons, risers and jumpers – all without ceasing production. Tracerco says that this offers savings of up to 35% over an inspection campaign compared to conventional techniques.

Yes we scan As with a medical CT scanner, Discovery uses a radioactive source to pass a photon beam through the chosen material. In this case however, a high-energy gamma-ray source means the beam is able to pass through much denser material, enabling the system to be used on coated and concreted structures.

The unit is mobilised in two 6m ISO containers –a workshop and an equipment store – and can be deployed from any vessel of opportunity with a 5-tonne crane, ideally with active heave compensation (AHC). The total weight of the unit subsea is approximately 70kg.

Once on the seabed, a work-class ROV is used to carry and manoeuvre the system over the desired pipeline. The system requires a 24V/5A DC supply, a maximum of 210 bar hydraulic pressure and Ethernet connections for operation, all made available through an integrated hot stab.

Once clamped onto the pipeline, the scanner spins around the full 360° circumference of the pipe to gather the CT data. Each image “slice” gathered covers around 15mm of pipe, and Discovery can move along the pipe automatically to build up a larger cross-section if required. It takes around one minute per revolution to produce a low-resolution scan, although NEWSBASE

more detailed images can be produced depending on the available time, and the pipe size, construction and circumference.

Tracerco says more detailed scans usually average between 5-15 minutes.

The captured data is then transmitted to the surface and, using Tracerco-developed software, processed in real time to give a detailed picture of the pipe walls, its coating and its contents. Internal systems within the system also record data to ensure there is no loss of signal, and for added redundancy.

Using the real-time data, Tracerco’s inspection team will prepare an accompanying interim report detailing any urgent anomalies or areas of concern, allowing operators to address any serious issues immediately. Following this, a more detailed analysis is prepared by the company’s engineers and its wider Technology Group.

Although final processed results will depend on individual assets, Discovery has recently completed a Lloyd’s Register qualification programme, resulting in the technology being certified. This puts the accuracy of wall thickness measurements to within +/- 1.5mm, and density to within +/50kg per cubic metre, with 80% confidence.

It can also identify pitting or metal loss with a minimum depth of 1.2mm.

Suitable for both vertical and horizontal, Discovery can scan pipe diameters from 6 to 26 inches (152-660mm) and can clamp onto pipes of up to 675mm diameter, including

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ASSET INTEGRITY Far left, Inset: The resulting scan image, showing details of all lines Below: Discovery™ is used to scan a coated pipeline with a piggyback line

coatings and other lines. It does require 360° access around these assets, which in the case of buried lines may mean some excavation is needed, but previous scans have successfully imaged even pipelines with high-density weighted concrete and rebar.

Bundles of information As outlined, the key benefit of Discovery is its unique ability to scan through coated and concreted pipes, avoiding the considerable time and expense of removing coatings to check integrity. But the flexibility of the system means it is also the first tool capable of providing a complete picture of more complex pipe architectures.

In the case of piggybacked pipes, typical inspections require full 360° access to each individual line to check integrity. Using external spacers, Discovery can clamp around the entire bundle, and perform a full scan of all lines simultaneously – another significant saving in time and cost. The scan also shows the bolts and pins securing the piggyback clamp itself.

The nature of pipe-in-pipe systems, often used to contain high-temperature products, also makes them a challenge to inspect.

Tracerco notes that Discovery has proved to be “particularly adept” at scanning these lines, in that it can provide accurate wall thickness measurements for both inner and outer pipes, as well as displaying the integrity and alignment of the spacing between the inner pipes. The same goes for

bundled pipes, where Discovery can offer clear integrity data on internal umbilicals, risers and even seam weld and rust accumulation.

In cases of hydrate and wax build-up, CT images will also provide insight into the size and formation of the deposits, and the ways in which they may be affecting fluid flow. In particular, it can also offer vital information on the presence and extent of under-deposit corrosion and localised pipe degradation underneath solid deposits – which are typically very hard to detect. In one deployment, Tracerco was able to identify hydrate formation and dissociation steps and accurately identify product pressure to within 0.1g/cubic cm, helping an operator devise a targeted solution to remove the build-up.

Following any remediation campaign, the system can also be used to confirm the removal of all deposits and verify whether pipe sections are completely clear.

What next?

Discovery has now been deployed successfully at depths down to 5,300ft/ 1,615m subsea, and has carried out in excess of 1,000 pipeline scans across the Gulf of Mexico, the North Sea and the Arabian Peninsula. Tracerco is currently considering the development of a larger unit, for lines of up to 42 inches (1,067 mm) in diameter.

Tracerco has recently announced the launch of a new fast scanning application for Discovery. Following customer feedback, NEWSBASE

the company completed further R&D work to develop a new method, specifically for detecting the presence of localised metal loss defects on subsea pipelines – up to 5 times faster than before.

The new development means that once a potential anomaly has been identified via the fast-scanning method, a more detailed and accurate scan to characterise it fully can be undertaken, simply by extending the duration of the fast scan. This eliminates the requirement of a separate scan and the need to deploy a secondary technology to validate the findings from the initial fast scanning inspection.

Operators can use this to screen subsea pipelines quickly and accurately to determine whether the integrity is within the acceptable tolerance specification. With non-intrusive inspection through any type of protective pipeline coating, defects can be fully characterised faster than ever, while again saving time, resources and the cost of an inspection campaign.

The first two inspection campaigns utilising Discovery as a fast-scanning technology have recently been completed on a large-diameter export pipeline in the Arabian Gulf and across a range of infield flowlines and jumpers in the Gulf of Mexico.

The quality and volume of inspection data obtained provided the clients with sufficient statistical confidence that the fast scanning results were representative of the condition of their entire system, Tracerco told InnovOil. As such, both customers were extremely satisfied with the results, providing another testament to this impressive technology. n Contact: Lee Robins, Commercial Manager, UK, Europe, Scandinavia, W. Africa Tel: +44 (0)1642 375532 Email: lee.robins@tracerco.com Web: www.tracerco.com

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InnovOil

December 2017

Stabilising production ASSET INTEGRITY

Well-Centric’s range of specialist well clamps help to secure and support unstable wells, providing a cost-effective alternative to conductor replacement

W

HILE the integrity of all aspects of oil and gas assets is undoubtedly important, wells are necessarily one of the primary concerns for operators. As many offshore wells age, their integrity is also compromised as a result of harsh marine conditions and years of production.

In cases where wells show signs of excessive movement, wellhead clamps are used to secure them.

Damage to well casing itself can cause movement of the wellhead, transferring loads to parts of the wellhead that are not designed to cope with them and causing scoring, fretting and rubbing damage. Remedying this requires the redistribution of those loads to parts of the well that have more strength, and can support and stabilise the well and any additional equipment.

Aberdeen-based well integrity and production technology specialist Well-

Centric has developed a range of clamps designed to centralise, stabilise and support wellheads and prolong the life of ageing wells.

Each wellhead clamp is designed using load calculations verified to prove the design is fit for purpose. The designs allow for normal expansion and contraction of the well over time as temperatures and production rates vary, whilst preventing excessive movement outside these accepted parameters.

Centralised operation In one recent case, Well-Centric was selected to centralise a well in the North Sea which had been experiencing excessive movement between the 30-inch (762-mm) conductor and the well casing, as a result of a damaged centraliser.

After inspecting the well with cameras, the operator discovered that this movement NEWSBASE

combined with the loose/damaged centraliser had been scoring into the conductor. An early consideration was to cut the casing, remove the broken centraliser and fit a replacement – at substantial cost.

Instead, Well-Centric designed a clamp that centralised the wellhead and limited excessive movement and therefore any further scoring in the conductor.

The team was tasked with designing a purpose-built well centralisation clamp which limited movement to prevent further scoring and damage, and which was capable of withstanding 25 tonnes of lateral force.

The clamp also needed to be easily fitted, removed and maintained, avoid interfering with existing wellhead equipment and

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with wellhead clamps ASSET INTEGRITY

Far left: Well-Centric centralisation clamp Left: Stabilisation clamp incorporate removable wear pads to prevent metal-to-metal contact.

Well-Centric produced a design incorporating six load fins, each capable of withstanding a 25-tonne load, along with adjustable and removable wear pads. Each fin had a 4-tonne shackle point for lifting during installation and grease nipples to allow the bolts to be lubricated during maintenance periods.

During deployment, the clamp was assembled in two parts, which were torqued together onto the conductor to prevent any slackening of bolts during rough tidal movement. In this case, speed was of the essence. The clamp was designed, built and deployed within an eight-week period and

installed by Well-Centric engineers offshore; installation was carried out in just one day.

One engineer remained on the platform post-installation to ensure the clamp continued to hold as designed and to observe any movement between the conductor and well casing. After three days, it was confirmed that no movement was taking place and that the installation had been a success.

The alternative repair option would have been to remove the conductor pipe surrounding the damaged centraliser and replace both the centraliser and conductor with new – a job worth in excess of GBP500,000 (US$660,000) when factoring in manufacturing, personnel to remove the existing damaged equipment and loss of production.

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With 70% of global oil production extracted from mature fields, conductor integrity issues are becoming a more common occurrence. While there is still life left in these fields, it is often not commercially viable to carry out expensive replacement repair operations. The production value from the field must justify the repair and so costeffective solutions such as those provided

by Well-Centric enable production from these brownfield assets to be maintained and prevent early abandonment of wells. n Contact: Rebekah Burnett

Tel: +44 (0) 1224 937 621 Email: rburnett@well-centric.co.uk Web: www.well-centric.co.uk

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InnovOil

The gas giant’s plans assume a slow recovery in the global energy market. Joe Murphy reports from Moscow

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December 2017

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Gazprom unveils revised strategy for the Russian shelf

T

HE oil price crash and the introduction of international sanctions in 2014 brought a number of Russia’s offshore projects to a standstill. Drilling work was halted as the country’s oil and gas producers shifted their attention to cheaper plays on land.

Authorities in Moscow later declared a moratorium on the issue of new offshore licences in the Arctic, aware that operators would struggle even to meet their existing exploration commitments. Some projects on the Russian shelf cannot move ahead, at least in the near term, without access to advanced Western technologies that are restricted by the US and EU sanctions regimes. Others have simply been rendered unprofitable to develop under current market conditions.

In recent weeks, however, Russia’s natural gas giant Gazprom and its oil-producing subsidiary, Gazprom Neft, have shed light on their development plans off the coast. Their revised schedule for bringing new offshore fields into production contrasts dramatically with forecasts made in the heady years when oil traded at over US$100 per barrel. This more cautious strategy assumes, at best, a slow recovery in the global energy market, in line with the Russian Economy Ministry’s guidance that oil will still be selling at under US$50 per barrel in 2020.

However, the strategy also leaves open the question of whether Gazprom will be able to secure the advanced technology necessary to develop some of the more NEWSBASE

challenging of these projects, either through domestic innovation or assistance from other suppliers, such as China.

Far north Gazprom’s offshore strategy to date has focused mainly on the two geographical areas – the western Arctic and the Sea of Okhotsk off the coast of Sakhalin.

Pechora is host to Russia’s only producing field on the Arctic shelf. Gazprom Neft’s Prirazlomnoye deposit, situated some 60 km from the mainland in a water depth of 20 metres, was launched in late 2013. The field delivered an output of 42,000 bpd in 2016, but this is slated to rise to 50,00052,000 bpd this year and over 60,000 bpd in 2018, thanks to continued drilling work.

Output is seen eventually rising to 90,000 bpd under the field’s first development stage. Prirazlomnoye produces a blend of oil containing high levels of sulphur, making it an ideal export to refineries in northwestern Europe. It holds over 70 million tonnes (513 million barrels) in recoverable oil reserves.

Gazprom Neft’s CEO, Alexander Dyukov, noted last week that the company would conduct seismic work at Prirazlomnoye next year. This is the first stage of a secondary development phase that will target the field’s deeper layers. Prirazlomnoye remains profitable despite low oil prices, with Gazprom Neft boasting a production cost of only US$10 per barrel at the site late last year. Like other Arctic projects, it also enjoys

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a zero rate on export duty and other tax breaks. Still, Prirazlomnoye’s development, which was planned as early as 1992, has been mired by delays and cost overruns, highlighting the operational challenges presented in the region.

Some 16 km north of Prirazlomnoye lies Gazprom Neft’s Dolginskoye oil and gas field, discovered in 1999. The company sank a well at the site in 2014, but plans for another two wells in the following year were cancelled after the market collapse.

However, Dyukov noted last week that the explorer aimed to conduct a shoot a 3D seismic survey at the field in 2018 with a view to drilling another well the year after. A final investment decision (FID) on this well has not yet been taken. At present, the field is estimated to comprise over 200 million tonnes (1.47 billion barrels) of oil and gas in recoverable reserves.

Gazprom Neft may be unable to develop Dolginskoye further without the Western expertise and technology it used at the site

InnovOil

in 2014. International service companies Schlumberger and Weatherford both provided technical assistance at the project prior to sanctions.

Gazprom Neft is looking for a foreign partner at the project, having signed a memorandum of understanding (MoU) with India’s ONGC on joint development in March this year. However, this partnership is designed to help shoulder costs rather than secure technology and expertise. Production at Dolginskoye is still a long way off, with Gazprom Neft estimating even before the oil price crash that the field would only be producing a modest 90,000 bpd of oil by 2027.

Given delays, it is unlikely that this milestone will now be reached before the 2030s.

Gazprom’s gas projects in the Arctic are an even more distant prospect.

In a strategy outlining its strategy until 2040, released earlier this month, the company said it aimed to launch the previously shelved Shtokman gas condensate field on the Barents Sea shelf in 2028.

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December 2017

Gazprom teamed up with France’s Total and Norway’s Statoil in 2007 to realise the troubled project. However, the partners were unable to agree on a feasible means of commercialising the field’s massive gas reserves, estimated at 3.9 tcm. Statoil and Total later exited the plan, with Gazprom conceding that the field would be left for future generations to develop.

Part of the issue was Shtokman’s gas was originally earmarked for the US market, but this became a less feasible option following the shale gas revolution in Texas and North Dakota. The field is stranded 550 km northeast of Murmansk at water depths of up to 340 metres.

In its strategy, Gazprom said the Kara Sea’s Leningradskoye gas field was not scheduled for launch until either 2034 or 2040. The field has C1+C2 reserves of 1.05 tcm of gas and 3 million tonnes (27 million barrels) of condensate. Gazprom completed an exploration well at the site earlier this year, using a Chinese-built rig.

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Previous page: Gazprom’s Prirazlomnoye field Far left:Yamal oil being shipped via the Arctic Gates oil-loading terminal at the Yamal Peninsula Left: Model of the gasprom plant at the exhibition Russia Looking to the Future, Moscow, Nov 2017 (Picture: Elena Abduramanova) Below: When finished, the Lakhta Center in Saint Petersburg will be the tallest building in Europe and will house Gazprom’s new headquarters (Picture: Sergei Sigov)

The company also controls Rusanovskoye field, also in the Kara Sea, which is estimated to hold 779 bcm of gas and 70 million barrels of oil in ABC1+C2 resources. Bu exploration plans have been disclosed for this site.

Despite their large reserves, these gas projects represented challenging projects even when the oil market was bearish. As such, their fate remains uncertain.

Far east Gazprom has made speedier progress in the Sea of Okhotsk, where it is developing several fields under its Sakhalin-3 project.

Last week, Dyukov said he expected to see the recently discovered Neptune oilfield come on stream in either 2025 or 2026.

Previously, the executive suggested it could eventually reach an output of 90,000-100,000 bpd. The deposit, situated on the Ayashsky block, is located 55 metres from the shore of Sakhalin in a water depth of around 60 metres. Gazprom Neft confirmed the field’s

existence earlier this month after a successful result at an exploration well. It is currently believed to contain 255 million tonnes of oil equivalent (1.87 billion barrels) of mostly crude oil, although exploration at the site continues.

Dyukov noted that the firm was not looking for a partner at Neptune at present, but did not rule out this option in the future.

He stressed that production from the field could generate profits even at current oil prices.

Gazprom’s other Sakhalin-3 licences are for the nearby East-Odoptinsky and Kirinsky blocks. Exploration at the latter area led to the discovery of the Kirinskoye, South-Kirinskoye and Mynginskoye gas fields. Kirinskoye came online in 2014 and is scheduled to reach a peak output of 5.5 bcm per year.

According to its long-term strategy, Gazprom does not expect South-Kirinskoye to come online until 2023, versus an earlier launch date of 2021. It will eventually NEWSBASE

produce up to 21 bcm per year of gas, drawing from a resource base of 1.4 tcm. The field was targeted directly by US sanctions in 2015, complicating Gazprom’s development plans.

Mynginskoye, meanwhile, is scheduled to start production in 2034.

In the last several years, Gazprom and other Russian energy companies have touted their progress in developing domestic technology that can substitute foreign imports. But according to most accounts, the Russian oil industry still remains heavily reliant on international suppliers. A report by the Russian Industry Ministry, which surfaced in the local press in February, claimed that foreign imports still accounted for 80% of equipment and technology used in the Russian upstream sector.

This suggests that Gazprom still has some way to go before it can advance its more technologically challenging and costly projects on the shelf without outside assistance. n

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InnovOil

December 2017

COMMENTARY

Premier Oil achieves Ca

The launch of production at Premier’s flagship Catcher field by the end of th major boost for the company as it looks to tackle its debt pile, reports Sam W

P

REMIER Oil successfully deployed and linked its floating production storage and offloading (FPSO) vessel BW Catcher at the Catcher oilfield in the North Sea on October 23.

The development has raised hopes that the company might be able to bring the delayed project online by the end of 2017.

This followed a successful hook-up of the submerged turret production (STP) mooring buoy system, with a successful rotation test completed three days earlier. Sources close to the project say that commissioning activities have now commenced in parallel to a final pull-in of risers and umbilicals.

Mobilising the FPSO into position has been the main holdup in the process of getting Catcher online following delays in its construction. The vessel was built by Japan’s IHI and Norwegian FPSO provider BW Offshore.

Premier’s plan is to ramp up production from Catcher first, followed by the satellite Varadero and Burgman fields nearby over the next three to four months. Catcher is comparatively stable, with a low gas to oil content. Peak production from the field is estimated to be 60,000 bpd of light crude, with the field estimated to have a productive lifespan of around 10 years. This should enable the company to hit its production target of 75,000 boepd in 2017, with some estimates suggesting that Catcher will triple Premier’s production in the North Sea. The FPSO will be on a seven-year charter with Premier, with a processing capacity of 60,000 bpd and storage capacity of 650,000 barrels. It will be linked up to 20 undersea wells in 91 metres of water.

Total capital expenditure on the project was initially projected to be around US$2.2 billion, but this has been cut back significantly thanks to cost savings in production and is now forecast to be US$1.6 billion. Premier owns 50% of the field and is the operator, with Cairn Energy holding a 30% stake and MOL holding the remaining 20%. The final development plan for the project was approved in June 2014, following Premier’s purchase of the fields as part of two purchases of Oilexco and EnCore Oil in 2009 and 2012 respectively.

Even if Catcher were to encounter further

delays, Premier now also has the 1 billion barrel Zama-1 field in Mexico in its portfolio.

This field, which was discovered in July, ought to reassure investors that the company has a bedrock of assets on which it build some production momentum.

Debt and restructuring Nevertheless, after a difficult few years, Premier is pinning much hope on Catcher, NEWSBASE

as are its shareholders, with the company’s share price jumping noticeably following its previous announcement that production could begin before the end of 2017. The company has been heavily in the red for some time, with a reported debt in excess of US$2.7 billion that has weighed heavily on operations.

Despite these challenges, a combination of supportive lenders and improved efficiency has allowed it to become cashflow positive

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COMMENTARY

atcher field milestone

he year would be a Wright from London

and begin reducing its net debts. This has led investors to believe that when Catcher comes online, deleveraging will accelerate.

In May, Premier said it expected to slash its debts significantly in 2018 by exceeding its 2017 production target and cutting spending across the board as part of a restructuring programme. This was followed by a major sale of the company’s 33.8% stake in the Wytch Farm onshore oilfield for around

US$200 million and its release of letters of credit adding up to US$75 million. As a consequence of the subsequent deal with Premier’s large and diverse creditor group, the company has until May 31, 2021 to repay its debts and must keep net debt at 8.5 times its earnings until the end of 2017.

Phased approach The fact that these debts remain on the books NEWSBASE

is an indication of how hard Premier was hit by oil price crash, which left many companies in difficult or unsustainable positions.

Nonetheless, Premier’s CEO, Tony Durrant, has high hopes that Catcher will be among the developments that leads to a change in fortune. Speaking to Energy Voice in July, he clarified his plans for the future. “We’re just about to finish this refinancing which has been protracted and rather painful but it sets us on a course for the next five years with our lender groups. We don’t have any debt to repay in the next five years. And broadly speaking, what we have done is agreed a business plan over the next five years, and that business plan splits roughly into two phases.

“The first phase takes us through to the beginning of 2019. We bring the Catcher field on stream later this year which will generate cash flow. We’ve got no immediate capex commitments beyond Catcher and we will be repaying debt. Subject to the oil price being halfway decent, we will get our balance sheet back in reasonable shape by the beginning of 2019.”

Phase two will then involve selective reinvestment to begin building back up once the debts are cleared. This still remains some time off owing to the size of Premier’s debt, even with the increased production from Catcher and output from its existing assets.

Despite the interest surrounding the installation of the FPSO, Premier has so far refrained from confirming publicly that delivery is set for the end of the year, although there is thought to be some optimism that this will be possible. At the same time, some industry voices have said that while some work is still required, an end-of-year target is actually feasible, and that first oil on or around Christmas Day is a possibility.

If this target can be met, it will do a great deal to reassure its creditors that the company is on the right track. Premier has said previously that it could generate a profit in 2017 on the back of higher oil prices and output, asset sales and reduced spending. A profitable performance for the year combined with the start up of Catcher would mean the company was in fairly good shape for the start of 2018. n

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InnovOil

December 2017

Propylene market set for Dow Chemical has developed a new method for the production of propylene from gas feedstocks, which it says could be up to 20% cheaper than existing methods. Ros Davidson finds out more

P

ROPYLENE is a vital intermediary in the production of plastics and countless other everyday products, and second only to ethylene in terms of global production volume. In 2016 just over 100 million tonnes were produced worldwide, and demand is still rising, with IHS Markit recording that this growth rate has been sustained at about 4% for the past 5 years.

Typically propylene is produced by steam-reformation of naphtha and LPGs, and as a by-product of catalytic cracking, but it can also be made on demand using propane dehydrogenation or olefin metathesis. The latter has become more favourable as feedstocks have shifted from naphtha (sourced from crude) to ethane (derived from gas) in light of the US unconventionals boom.

A new downstream technology developed

by Dow Chemical can manufacture propylene directly from shale gas, potentially offering savings of more than 20% versus other commercial processes. Dow’s fluidised catalytic dehydrogenation (FCDh) process

also reduces the energy requirements per pound of propylene produced. Moreover, its manufacture can be integrated into existing or new production processes for propylene, ethylene and other valuable hydrocarbon intermediates – meaning uptake could be fast.

On November 17, FCDh was named as one of the winners of the annual R&D 100 Awards, which recognise the best new technologies of the prior year. The awards are the most prestigious acknowledgement of invention and innovation globally.

Olefin tech FCDh uses a similar process to Dow’s already commercially available fluidised catalytic cracking (FCC) technology. But FCDh uses a different catalyst and a different set of process conditions, said Andy Arthur, R&D director at Dow’s hydrocarbons & energy and ethylene oxide-ethylene glycol businesses. “It uses a different feedstock that allows selective dehydrogenation to a specific olefin,” he told InnovOil. Olefins, or alkenes, are produced during cracking.

As the production of shale gas has surged

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in the US, an imbalance has emerged in the supply and demand of propylene. That is because of the shift to lighter cracker feedstocks – because of shale gas – and slowing gasoline demand for refineries.

Historically, propylene was an abundant co-product from ethylene production via refinery FCC and non-ethane steam cracking processes. “Since the shale revolution caused increased production of raw gas that contains more natural gas liquids, like ethane and propane, this has lowered global propylene production, creating a propylene shortage,” explained Arthur.

Dow said that it recognised the importance and limitations of existing propane dehydrogenation technology, and so moved to develop FCDh. The technology had originally been devised for the production of ethylene and styrene during 2000-2006, but was then adapted to propane dehydrogenation during 2008-2016.

The savings come from higher efficiencies and a lower overall cost. Existing propane dehydrogenation (PDH) technologies – in which propane is selectively dehydrogenated

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catalytic conversion Main image: The Dow Chemical chemical plant in Stade, Germany, is a major manufacture of propylene (Andreas Rose / Shutterstock.com) to propylene – work by slowly moving deactivating catalysts between reactors and a regenerator. This is the PDH technology already implemented around the world.

“The FCDh technology takes a very different approach, using more active catalysts with shorter times between regenerations,” said Arthur. “This leads to lower overall capital investment, fewer limitations on increasing scale, higher efficiency and better operability.”

He added: “Dow’s FCDh technology manages the fundamental constraints of the chemistry with a simple, efficient and multifunctional process design. The new technology enables shorter contact times for the feedstock over the fluidised bed with close-coupled cyclones for catalyst/product separation. Frequent catalyst regeneration creates higher effective catalyst activity while in service.”

Thermally efficient The lower energy requirement, per pound of olefin produced, is because less heat is needed to drive the conversion for PDH. “We applied

a concept of using the catalyst to carry heat to the reactor,” said Matt Pretz, one of the FCDh technology developers who worked alongside colleagues Lin Luo, Mark Stewart, Brien Stears, Isa Mbaraka, Richard Pierce and Susan Domke, at a Dow lab in Freeport, Texas.

“This approach really improves the energy efficiency, but makes very little coke,” said Pretz in reference to the side reactions and coke formation which can occur during PDH conversion. “To satisfy the required energy balance in FCDh, we use the catalyst to independently control the reactor temperature and add supplemental fuel to the regenerator. The challenge lies in balancing the chemistry and process parameters to optimise yield and overall energy input.”

Moreover, the FCDh technology is more flexible, Dow said, and can be integrated into existing or new ethylene crackers either to increase production, or so that facilities can be tailored to produce a specific amount of ethylene and propylene. “This enables producers to “flex” their production ratios using shale gas resources in their existing

NEWSBASE

processes, allowing them to quickly respond to changing market dynamics, while saving capital and energy versus existing commercial processes,” explained Arthur.

In addition, FCDh can be used in other aliphatic and alkyl aromatic dehydrogenation processes, he added, because the FCDh catalyst can perform the dehydrogenation of paraffin and alkyl aromatic compounds such as ethane, propane, butane, isobutane and ethylbenzene.

Given that there appears to be no shortage of unconventional feedstocks, and a solid demand forecast, process technologies like FCDh could have a fairly swift impact on the bottom line of chemical producers in the next few years. Dow is currently exploring commercial options to advance the technology and says it has received favourable interest from potential customers.

It may not be long before FCDh begins to make its mark in the marketplace. n Contact: Jim Perry

Email: JimPerry@Dow.com Web: www.dow-dupont.com

InnovOil

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Statoil activates Valemon automated rig control room

December 2017

Sam Wright reports on the Norwegian NOC’s first fully automated offshore design

S

TATOIL has switched on the control room for its Valemon remotely controlled offshore platform on the Norwegian Continental Shelf (NCS).

It is the first time the state-run Norwegian oil company has used a fully automated offshore design at one of its projects.

The control room in Bergen will be manned by 14 staff members on seven shifts, and will oversee every aspect of the rig, which primarily produces natural gas and condensates.

Valemon is initially programmed to run for four-week production periods followed by two weeks. During this period the rig will be manned to allow for inspection and maintenance, following the standard Norwegian model for work periods but letting the platform run with one-third of its normal crew. The field produces around 60,000 boepd of gas and condensate. It normally operates with a crew of 40.

Gunnar Nakken, Statoil’s production director, described the project as a “vital milestone”. “We have had land-based surveillance and control of offshore operations for a long time; however, the remote control of Valemon marks one important step forward on our digitalisation journey,” he added.

Valemon came online in January 2015, delivering gas via the Huldra/Heimdal pipeline to Kvitebjorn and then on to Bergen. The field was already tied to existing infrastructure via subsea pipelines when it opened, and it contains around 192 million boe in a fragmented, high-pressure, hightemperature (HPHT) reservoir. It is owned

and operated by Statoil with a 53.77% interest, while Petoro owns 30%. Centrica holds 13% and Royal Dutch Shell has 3.23% Speaking to InnovOil, Statoil’s development, production and exploration communications manager Morten Eek stressed that the company considered Valemon “a test bed for the future full automation of small and medium projects”.

He went on to say that many of the NOC’s larger platforms and projects (including the Johan Sverdrup platforms due to come online in 2019) would still be fully manned.

Kvitebjorn in particular, he added, is crucial to the Valemon platform’s operations because it hosts the emergency response team and a secondary control room to handle problems at the offshore site that the Bergen control room cannot. It also hosts backup emergency shutdown controls and monitoring systems, providing communication if the platform is cut off from the mainland. These features are standard on many stand-alone rigs worldwide, but the unmanned aspect is new: Valemon will be one of the first normally manned rigs to predominantly operate without a crew on board.

Key advantages Unmanned rigs provide a number of advantages. So far, most unmanned facilities have been part of a larger development with a manned core, such as the Normally Unmanned Units which operate across the North Sea for a variety of operators in conjunction with manned assets.

In harsher or more remote environments, however, unmanned or semi-manned rigs are NEWSBASE

more energy efficient. They are also less prone to crew injuries or loss owing to reduced crew operating time on the rig and are cheaper to supply over the long term in terms of paying crews, arranging transport and providing habitation blocks.

While the Valemon rig has run manned for more than two years at this point, future

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Top: Valemon onshore control room Above: Valemon offshore platform (Photo: Harald Pettersen Left: Gunnar Nakken, head of the operations west cluster in Statoil, Norwegian minister of petroleum and energy, Terje Søviknes, head of Kvitebjørn Valemon and Grane operations, Nina Birgitte Koch and control room operator Joakim Tesdal (Photo: Christian Djupvik and Brandt-Hansen)

rigs designed when the technology is mature could be built with the bare minimum of habitation for a much smaller maintenance and inspection team, allowing for cost savings in the long term. Statoil is already moving towards standardised, modular “building blocks” when building future rigs, allowing them to attach components and segments as

needed and combine resources optimally for efficient resource exploration.

This technology is still very much in its infancy, however. Statoil’s two major upcoming projects, the Aasta Hansteen and Johan Sverdrup platforms, will still be manned, albeit heavily digitalised and equipped with the latest automation systems.

NEWSBASE

As a wider trend of digitalisation, the general automation of the offshore oil and gas industry is progressing as more companies take steps towards operations like Valemon.

Advances in drone technology, rig security and on-board automation are increasing the feasibility of an entirely unmanned rig with every new development. n

InnovOil

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Drillers sign joint venture for deepwater Egypt Vantage Drilling International and ADES International Holding have reached a deal to form a joint venture to provide drilling services in the deepwater Mediterranean basin, off Egypt. ADES has previously focused on shallow-water work.

According to a statement on November 15, the project will bring together Vantage’s deepwater drilling fleet, which consists of three ultra-deepwater drilling ships, four premium PMC jack-up rigs and a standard jack-up rig, with two more drilling ships under construction. ADES’ will provide its expertise and experience of working in Egypt.

The deal appears advantageous to both sides.

ADES will receive discounted and bareboat charters of drilling units, while Vantage will gain the contacts and expertise to expand into a new market. At the same time, both will share profits and have exclusive deepwater marketing rights within Egypt itself.

ADES’ CEO, Mohamed Farouk, said the joint venture would benefit both sides. Farouk described ADES’ focus on “shallow, non-harsh environments” and that while this remained at the heart of its strategy, “our long-term joint venture with Vantage will extend our reach into deepwater drilling, while retaining our low-cost model”.

Vantage’s CEO, Ihab Toma, praised ADES and said the venture would provide both sides with additional capabilities, “thereby providing a unique service in Egypt”.

This approach in particular will means that ADES can expand into an entirely new type of drilling without a significant capital outlay for new equipment or research, working alongside

an operator already experienced in these processes.

Demonstrating its focus, ADES announced a new contract for one of its jack-ups on November 16. The Admarine III has signed up for two years of work with Egyptian General Petroleum Corp. (EGPC), with an option for a two-year extension. The rig’s first contract with EGPC, in 2012, was the company’s first move into the offshore market. n Edited by Ed Reed edreed@newsbase.com

Baker Hughes ties up with Sudan partner US oil service company Baker Hughes has signed a memorandum of understanding (MoU) with Sudan’s Asawer Oil and Gas for co-operation in exploiting the East African country’s under-developed natural gas sector.

In a statement released on November 13, Asawer Oil and Gas, the technical and financial arm of the state-owned Sudapet, said the co-operation agreement would involve the two companies working together in the implementation of gas and associated gas projects, as well as co-operation in providing spare parts and drilling fluids.

Speaking at the signing ceremony in Khartoum, Baker Hughes’ CEO, Lorenzo Simonelli, expressed his firm’s readiness to invest in Sudan’s gas and oil services. Sudanese Oil and Gas Minister Abdel Rahman Osman called for external investment in Sudan’s Red Sea oil and gas fields. Sudan has proven gas reserves totalling 84.95 bcm, but, in terms of exploration and pipeline infrastructure, development has been limited.

Vantage Drilling International ‘s Titanium Explorer

NEWSBASE

Simonelli said the lifting of US sanctions on Sudan would encourage foreign firms to work in the country. On October 12, the US dropped a 20-year-old trade embargo on Sudan, removing many companies from the list of specially designated entities, including firms in the petroleum sector.

The lifting of the oil-related sanctions has been touted as a much-needed economic impetus for Sudan, which remains one of the world’s poorest countries. When South Sudan seceded from Sudan in 2011, it took away threequarters of the latter’s oil production.

Sudan has recently entered discussions on the development of its hydrocarbons industry – including its petrochemical sector – with Russia’s Lukoil and with other firms from Europe and Canada, Osman said on November 14. Osman commented on foreign companies being interested in developing onshore projects as well as offshore natural gas projects in the Red Sea. n Edited by Ed Reed edreed@newsbase.com

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East Africa Crude KCA Deutag Oil Pipeline secures land drilling contracts for five rigs UGANDA and Tanzania last week marked their commitment to the East Africa Crude Oil Pipeline (EACOP) with an inauguration ceremony in the town of Hoima, near Lake Albert, where the conduit will originate.

The occasion follows one held last August in Tanzania, where the 1,445-km pipeline will terminate at the Indian Ocean port of Tanga.

EACOP will cost an estimated US$3.5 billion and be the longest heated pipeline in the world, necessary to ensure the flow of Uganda’s waxy crude.

Front-end engineering and design (FEED) work for the 220,000 bpd project is due to be completed by the end of the year and a final investment decision (FID) is expected in the coming months.

Construction will be undertaken by a joint venture company comprised of the two governments and Total, Tullow Oil and China National Offshore Operating Co. (CNOOC), which are working to develop Uganda’s estimated 6.5 billion barrels of oil reserves, of which 1.7 billion are estimated as recoverable.

Work will begin in early 2018 and is anticipated to take 36 months to complete. n Edited by Ian Simm ians@newsbase.com

Leading international drilling and engineering contractor KCA Deutag today announces that its land drilling operation has been awarded new contracts for five rigs with a combined contract value of $48 million. The first of those rigs, the T-72 has been awarded a nine month contract in Pakistan for one firm well, with an additional one well extension option.

KCA deutag land rig

NEWSBASE

In Europe the T-700 which recently completed two geothermal wells in the Netherlands has also won a five month contract for an additional four wells with the same client. This is the group’s sixth contract in the European geothermal drilling market in recent years, and an area which offers substantial growth opportunities for the group as Europe seeks to increase its renewable energy generation.

Our operation in Algeria also signed a new contract for our T-220 fast moving desert rig with a client drilling two firm wells and two optional wells. The total campaign, including the optional wells will take a total of around one year.

In the Middle East, KCA Deutag was also recently awarded a one year contract for two rigs, the T-210 and T-601, to carry out land drilling operations in South Iraq. The T210 will move from Oman for this opportunity, bringing the total number of rigs in South Iraq up to three.

The majority of these rigs were manufactured by Bentec, KCA Deutag’s land rig and oilfield equipment manufacturer.

Bentec manufactures a wide range of rigs that can deliver high performance drilling and fast rig moves in all climates and geographies.

Commenting on these contract awards, Simon Drew President of Land said: “These contract wins, which come in a tough environment in the wider oil industry, are very important to the Land Business Unit and KCA Deutag as a whole. They have been won against intense competition and I would congratulate all our staff on delivering these contract successes. We look forward to delivering value to our clients through exceptional well construction performance.” n KCA DEUTAG

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InnovOil

December 2017

NEWS IN BRIEF INEOS Dragon Ship

ExxonMobil to evaluate petchems complex in Huizhou US major ExxonMobil has reportedly signed a strategic cooperation framework agreement and a memorandum of understanding (MoU) with the local government of China’s Huizhou region to jointly evaluate a new petrochemicals complex. The local government said the partnership agreement is aimed at creating a petrochemical industry base in the Daya Bay area on the south coast of China, according to the South China Morning Post.

“The complex, which will adopt advanced industry and environmental protection technologies, meets the needs of Guangdong [and will help] to further open up and upgrade the industry structure,” Governor of Guangdong province Ma Xingrui was cited as saying. “We will enhance policy support for foreign investors and offer key support to build a world-class petrochemical industry base in the Daya Bay area,” he added.

The Huizhou government said the new complex would include a steam cracking device and a matching olefin derivative processing unit. “ExxonMobil plans to invest billions of US dollars and build a petrochemical complex in Huizhou with leading technologies, highest safety standards and optimal operation experiences,” president of ExxonMobil Chemical Company Neil Chapman was also cited as saying.

There are already several refineries and petrochemical production facilities in the Daya Bay area including the Huizhou refinery.

The facility, which is part of the second phase of Chinese oil producer CNOOC’s Huizhou refining and chemical complex, is currently undergoing a 200,000-bpd expansion.

The complex, a joint venture between CNOOC and Anglo-Dutch major Shell, includes a 1.2-mtpa ethylene plant. For the last two decades, China has been strengthening its oil refining capacity to meet the needs of rapid demand growth. As part of those efforts, it began issuing import licenses to private companies known as ‘teapot’ refiners, which now account for around 12% of China’s crude demand. n Edited by Andrew Kemp andrew.kemp@newsbase.com

INEOS to deliver shale-gas ethane to China in 2019 INEOS has announced a long-term supply agreement with SP Chemicals to deliver ethane from US shale gas to China. The agreement, which will see US ethane from shale gas shipped to China for the first time, will supply SP Chemicals with a long-term competitive supply of ethane for its industrial production.

The deal will involve the construction of a 95,000cbm capacity ship which is expected to be delivered in 2019. Known in the US as a ‘Very Large Ethane Carrier’ or VLEC it will be the largest ethane carrier in the world, and will ship US ethane from shale gas to SP Chemicals’ new gas cracker facility, currently under construction in Taixing China. As with the INEOS Dragon ships, this vessel will be operated by EVERGAS. It will be the first VLEC in their fleet of 23 gas ships. The ship will be built in China under the management of the JACCAR Group.

Ethane is used to make ethylene - one of the world’s most important chemical building blocks. Ethylene is an important raw material used to make products for a wide variety of industrial and consumer markets such as transportation, electronics, textile and construction.

Chan Hian Siang, CEO of SP Chemicals, said: “SP Chemicals is honoured and very happy to work with INEOS, a first-class global company, to ship ethane over a journey of more than 18,900 km across the Pacific Ocean from USA to Taixing City, Jiangsu province, PRC. It has long been a dream for SP Chemicals NEWSBASE

to integrate upstream. SP Chemicals will commission a gas cracker plant in 2019 to produce 650,000 tons per annum of ethylene.

This first long-term supply agreement for ethane with INEOS will be an important milestone for SP Chemicals to achieve self-sufficiency for its ethylene requirements.” n INEOS

WorleyParsons buys Amec Foster Wheeler The UK oil and gas arm of services firm Amec Foster Wheeler has been sold to Australia’s WorleyParsons for GBP182 million (US$239 million). The closure of the deal follows a long period of uncertainty and a tight bidding war between multiple international companies.

The sale, which was ordered by the UK’s Competition and Management Authority, will go some way to easing concerns over a potential monopoly created in the North Sea service industry by Amec after its proposed GBP2.2

Amec Foster Wheeler announces the aquisition o

December 2017

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NEWS IN BRIEF

billion (US$2.9 billion) merger with Wood Group was unveiled in March.

The deal was announced on October 9 and completed on October 31. Initial reports valued the deal at GBP228 million (US$299 million), but the final price was reportedly GBP182 million (US$239 million).

Amec’s UK oil and gas arm holds a number of long-term service contracts with various oil and gas operators in the North Sea. These involve multiple levels of the product delivery phase as well as project delivery, consultancy, commissioning, efficient and smart asset support and decommissioning. It employs more than 3,000 people at its Aberdeen headquarters and works with upstream, midstream and refining operations for oil, gas, LNG and a variety of petrochemicals. n Edited by Ryan Stevenson ryans@newsbase.com

Weir Oil & Gas introduces WMSS10 Mudline Suspension System

Weir Oil & Gas has announced the introduction of its WMSS10 Mudline Suspension System for exploratory and developmental wells. This stack-down system eliminates debris traps,

on its web site’s home page

improves reliability and enhances efficiency of tieback operations in offshore operations.

Weir’s WMSS10 Mudline Suspension System transfers the weight of the well to the seabed.

It offers a method of disconnect for all casing strings, allowing the temporary abandonment of a well in a minimum amount of time and without having to cut casings. Casing strings can be easily reconnected for surface completion on a production platform wellhead deck.

The WMSS10 Mudline Suspension System features a series of hangers with landing and load rings located on load shoulders to transfer the weight of each casing string to the conductor and the seabed while drilling from a jack-up.

The WMSS10 is designed for high-capacity casing hang-off loads and high pressure STD and H2S wells to allow operators to run casings to deeper depths. The stack-down configuration provides a washout point below the previous sealing area.

Metal-to-metal sealing protects against high pressures and corrosive fluids while separate running and tieback threads offer protection during drilling and temporary well abandonment. Generous flow-by areas maximize circulation during the cementation process. Additionally, generous washout ports in the running tool eliminate cement contamination. Long lead-in allows for selfaligned easy stabbing.

The standard casing configuration is 30” x 20” x 13-3/8” x 9-5/8” with 10,000 psi working pressure for STD and H2S application. n WEIR OIL & GAS

NEWSBASE

Schlumberger launches advanced digital integration of rock and fluid analysis services Schlumberger has inaugurated the newly expanded reservoir rock and fluid analysis laboratory located in Houston, Texas. The stateof-the-art lab enables petrotechnical experts to better leverage physical and digital rock and fluid analysis for comprehensive reservoir characterization.

The Houston Reservoir Laboratory features a leading portfolio of Schlumberger reservoir characterization technologies, which span downhole rock and fluid data and sample acquisition through wellsite and lab analysis.

Integration of data and insight from field and lab measurements in the DELFI* cognitive E&P environment enhances collaboration across exploration and production teams to realize the full potential of all available data and science in optimizing oil and gas assets.

“Digital technology is fundamentally changing the way the E&P industry works,” said Hinda Gharbi, president, Reservoir Characterization Group, Schlumberger. “The expansion of the Houston Reservoir Laboratory

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NEWS IN BRIEF

accelerates our customers’ access to our proprietary technologies, digital models and petrotechnical domain expertise to overcome technical challenges across the life of the field.”

The 123,000-square feet facility is staffed by scientists, engineers and technicians working across the spectrum of reservoir rock and fluid analysis. They employ innovative technologies for characterizing the reservoir to improve hydrocarbon production and recovery, including Maze microfluidic SARA analysis, unique Fluid Inclusion Technologies (FIT), Malcom interactive fluid characterization software and CoreFlow digital rock and fluid analytics services.

As part of the Schlumberger global network of rock and fluids analysis laboratories, the Houston lab also houses the Schlumberger Production Technologies Center of Excellence for conducting research, formulation and testing of production chemicals. n SCHLUMBERGER

Novatek shores up prospects at Yamalo-Nenets field NOVATEK, Russia’s leading independent gas producer, has signed off on the launch of trial production at the West-Yurkharovskoye gas and condensate field in Western Siberia, following an encouraging well result.

In a statement on November 13, the company said it had reached a final investment decision (FID) on further exploration and pilot production at the deposit, which lies across the Nadimsky and Tazovsky district of YamaloNenets.

The move comes after its local subsidiary, Novatek-Yurkharovneftegas, successfully tested liquid flows at a well targeting the field’s Jurassic reservoir. Well 135R was drilled to a depth of 4,100 metres using multi-stage hydro-fracturing technology. It registered an abnormally high reservoir pressure of 820 atmospheres, achieving production from two separate Jurassic horizons.

“This was the first time such a well completion for an over-pressurised Jurassic reservoir was applied in Russia,” Novatek said in its statement, adding that the well had naturally flowed a gas condensate mixture at a rate of 650,000 cubic metres per day. “The commercial viability of the deeper Jurassic deposits was confirmed, and, correspondingly, an investment decision was made to commence an exploration programme and pilot production from this new project site as part of the Yurkharovskoye production centre.”

Novatek did not disclose a timeframe for the project, nor its estimated cost. The WestYurkharovskoye field, some 175 km northwest from Novi Urengoy, was discovered in 2008. It is located adjacent to Novatek’s Yurkharovskoye field, one of the largest gas producing deposits in Russia.

Discovered in 1970, Yurkharovskoye was brought on stream in 2003 and produced 33.8 bcm of gas in 2016, accounting for

Novatek is to fire up trains 2 and 3 ahead of schedule at the Yamal LNG export terminal

NEWSBASE

around half of Novatek’s output that year.

Novatek’s other major gas producers are the Vost-Tarkosalinskoye, Khancheiskoye and Samburgskoye fields, also situated in YamaloNenets. With Yurkharovskoye and these other fields in decline, Novatek is scrambling to bring new projects on stream to maintain production levels. The company’s output will receive a lift later this year when the first 5.5 million tpy train of its three-train Yamal LNG export terminal starts operations. n Edited by Joe Murphy josephm@newsbase.com

Turkey to receive new MOL Challenger FSRU Turkey is to take delivery in November of Mitsui OSK Lines’ (MOL) Challenger FSRU. The vessel, which is the largest FSRU in existence with a capacity of 263,000 cubic metres, will be anchored near Dotyol on Turkey’s southeastern Mediterranean coast for the next three years, on lease to Turkey’s pipeline operator Botas.

This is the second FSRU to be installed in Turkey, which is expected to grow its LNG demand in coming years in order to counter gas shortages like it experienced last winter.

The MOL Challenger was built by South Korea’s Daewoo Shipbuilding & Management Engineering and has the capacity to regasify 11,000 tonnes per day of LNG. The 345-metre vessel was originally contract to Uruguay’s Gas Sayago and was to be anchored near Montevideo for 20 years, but that project has stalled, in the meantime, it will be anchored in southern Turkey. It has a regasification discharging capacity of 540 mcm.

Earlier this year, Turkey installed the 145,130 cubic metre GDF Suez Neptune at Calmakli near the Aegean city of Izmir, identified as the ETKI LNG Terminal project.

The Neptune was chartered from Norway’s Hoegh LNG by France’s Engie. It has a capacity to store 85 million cubic meters of gas and to process 7.75 bcm per year.

Turkey has two onshore regasification terminals: one at Marmara Ereglisi, operated

by Botas, and the other at Aliaga, operated

by Egegaz, also on the Aegean. The have regasification capacities of 6.2 bcm per year and 6 bcm per year.

During 2015, Turkey imported 7.4 bcm of LNG, followed by 7.6 bcm in 2016. That volume

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accounted for 16% of Turkey’s natural gas imports. In 2016, Marmara Ereglisi and Egegaz imported 5.484 bcm and 2.123 bcm of LNG respectively.

Turkey imports 99% of its gas demand, but consumption has declined over the last two years. The country required 46.2 bcm in 2016, down from 48.4 bcm in 2015 and from 49.2 bcm in 2014.

The country’s pipeline gas comes from Russia, Iran and Azerbaijan. LNG supplies come from Nigeria, Algeria and the spot market. n Edited by Richard Lockhart richardl@newsbase.com

online in the fourth quarter of 2017, which is anticipated to raise its net production in the region to over 120,000 boepd by the end of the year.

The Faith Marie 1-H well is located next to Devon’s seven-well Coyote development in Blaine County, which it began drilling in September. The projected 30-day rate for the 9,000-foot (2,743-metre) lateral well is 4,600 boepd, comprised of 65% oil.

The Faith Marie 1-H well’s productivity is the highest of any STACK well so far that

Devon brings high-rate STACK well online DEVON Energy announced last week that it had brought online a Sooner Trend Anadarko Basin Canadian and Kingfisher Counties (STACK) well in Oklahoma with a high peak rate. The Faith Marie 1-H achieved a 24-hour rate of 5,100 boepd.

The Oklahoma City-based company also said it would bring around 25 STACK wells NEWSBASE

targets the Lower Meramec interval, said Devon.

Devon used a new completion design for the well that it said improved stimulated rock volume through the systematic cycling of pressure and fluid rates while lowering well costs to US$9 million. The well also used a higher viscosity slickwater fluid system, increases in frack stage length and other proprietary modifications compared with legacy wells, said the driller.

“The advancement of Devon’s multi-zone

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development activity in the STACK coupled with the deployment of our cutting-edge completion design is expected to improve capital efficiencies by up to 20% while continuing to deliver best-in-class well productivity in the play,” said Devon’s chief operating officer, Tony Vaughn.

The company’s drilling programme at Coyote has reached target depth on three wells, with drilling times improving by roughly 15% compared to the results of the offsetting Faith Marie well.

Devon has three rigs dedicated to the Coyote project, and initial production (IP) rates are anticipated to be announced in the first quarter of 2018.

Drilling also is under way at Devon’s Showboat project in Oklahoma’s Kingfisher County, which is the company’s first multizone development in the STACK play. It consists of 24 wells across two drilling units, which are co-developing four intervals.

Devon is currently running five rigs at Showboat and expects to complete the drilling phase by the end of the year.

IP rates at Showboat are due to be reported in the second quarter of 2018.The development is offset by the Privott well, which Devon said had achieved a recordsetting peak rate of 6,000 boepd in July. n Edited by Anna Kachkova annak@newsbase.com

Petrobras and BP to form strategic alliance Petrobras has begun negotiating a strategic alliance with BP, which was announced days after the two companies bid successfully for two pre-salt blocks in Brazil’s latest bid rounds.

The companies have signed a letter of intent (LoI) to “identify and evaluate business opportunities together, involving assets or enterprises in Brazil or abroad,” Petrobras said. The state-run company said it and BP were looking at “exploration and production, refining, gas transport and commercialisation,” as well as “oil trading, lubricants, aviation fuel, energy generation and distribution, renewables, technology and low carbon initiatives with the view to developing a potential strategic alliance.”

Petrobras’ CEO, Pedro Parente, told local media after an event in Rio that a key focus of the alliance would be natural gas. “[The strategic alliance] permits Petrobras to increase the amount of gas in its portfolio,” he was quoted as saying by the Valor Economico.

The companies picked up two pre-salt blocks in the bid rounds held by Brazil’s upstream regulator, the National Oil Agency (ANP), on October 27. The companies won

Air BP refueller, Galeao Airport in Rio De Janeiro

NEWSBASE

the Peroba block in the Santos Basin, with each taking a 40% stake and China’s CNODC taking 20%. The consortium offered 76.96% of production and agreed a US$610 million signing fee to win the block.

Meanwhile, BP and Petrobras split equal shares for the Alto do Cabo Frio Central block in the Campos Basin by offering 75.8% of production and paying a US$152.4 million signing fee.

In March, Petrobras signed a strategic alliance with Total, with the French company paying US$2.2 billion to farm into 22.5% of the Petrobras-operated Iara concession and also to secure 35% and operatorship of the Lapa field in the Santos Basin.

Total also bought 50% of two gas-fired thermal power plants (TPPs) in Bahia in northeastern Brazil, along with access to a regasification plant. It has been expanding its alliances with global oil majors and also has a deal with Statoil to look at deepwater reserves in mature fields.

In related news, the Brazilian company has also said it was due to be paid US$25 million from Rolls Royce after the UK-based company signed a leniency deal with Brazilian prosecutors that are investigating graft. The sum represents Rolls Royce’s net profit on six goods and services supply contracts, Petrobras said. n Edited by Ryan Stevenson ryans@newsbase.com

December 2017

InnovOil

What next …?

To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections

If Tracerco’s Discovery™ subsea CT scanner could offer you greater insight into pipeline integrity, please contact Lee Robins, Commercial Manager for UK, Europe, Scandinavia and West Africa, on +44 (0)1642 375532, or alternatively, email lee.robins@tracerco.com If Avitas Systems’ application of autonomous systems and machine learning could change your approach to asset integrity management, speak with Jeff Plaskon, Head of Solution Sales on +1 216 338 2396 or email Jeffrey.Plaskon@ge.com For more information on Well-Centric and its range of well integrity and production technology – including well clamps – contact Rebekah Burnett on +44 (0) 1224 937 621 or rburnett@well-centric.co.uk Dow Chemical’s fluidised catalytic dehydrogenation (FCDh) process could be revolutionary in the propylene production market.

For information on licensing the technology, contact Jim Perry at Dow Chemical via JimPerry@Dow.com, or visit www.dow-dupont.com For more information on graphene-based filtration from the University of Manchester’s National Graphene Institute (NGI), contact Ben Robinson ben.robinson@manchester.ac.uk or visit www.graphene.manchester.ac.uk To learn more about Lawrence Livermore National Laboratory’s efforts to 3D print marine-grade steel, contact Jeremy Thomas at thomas244@llnl.gov

NEWSBASE

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Mark Hampton, Manager of Exploration and Technology, Shell Exploration and Production Inc. Published by

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