InnovOil Issue 45 September 2016

™ Published by

NEWSBASE

Bringing you the latest innovations in exploration, production and refining Issue 45

CAPTAUR THE FLAG

How the SeaCaptaur system could unlock the world’s small pools Page 8

ROCK ON

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

BREAKING BONDS

The chemicals and fluids revolutionising the oilfield Page 17

September 2016

R to Registe the d atten nCe e ConfeRition: & exhib

gy igentener ll te n .i w ww /register event.com

The leading e&P evenT for The nexT wave of smarTer, safer and more efficienT Technology New HorizoNs: iNtelligeNt eNergy iN a CHaNgiNg world

“This event will provide a forum to discuss the short term tactics to manage the downturn and learn about these new technologies to see how they are used in our industry and other sectors, and how they can accelerate us into the future upturn.”

WalT aldred, schlumberger

> Join 2,000 E&P industry experts from the world’s leading operators, service companies and technology providers

> 25+ innovative exhibitors

> Discover cost-saving and production enhancing solutions at the free to attend exhibition and SPE-produced conference

> 100+ speakers

> 3 plenary sessions > 75+ technical papers

amy Zeringue, Chevron Executive Committee Co-Chairs

From the organisers of: Organised by

5-8 SEPT 2017

InnovOil

September 2016

page 3

Inside A note from the Editor

5

High-pressure water

6

Contacts:

SeaCaptaur system

8

Media Director Ryan Stevenson ryans@newsbase.com

Smart Rocks

12

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

On the radar

14

Editor Andrew Dykes andrewd@newsbase.com

CHEMICALS & FLUIDS 17

A friendlier alternative to fracking could be high-pressure water drilling

SeaCaptaur’s technology could help unlock billions of barrels in small pools

Sensor-packed models which will offer insights into oil microporous structures

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

Where to turn in a downturn 18

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

AkzoNobel explains how it is supporting oilfield service customers in tough times

Nanofluid expectations

Phone: +44 (0)131 478 7000 www.newsbase.com www.innovoil.co.uk

Collaborative arrangement 22 TETRA Technologies explains their collaborative approach

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

NEWSBASE

ations Bringing you the latest innov

in exploration, production

The hub of the matter

25

DSME’s LNG icebreaker

26

Blurring the lines

28

Damen goes for decom

31

News in brief

32

EC-OG’s Subsea Power Hub could change the economics of subsea equipment ™

Published by

20

Researchers have developed a new nanofluid for use in EOR, with some heady results

Navigating the icebound waters of the Russian Arctic

and refining September 2016

Issue 45

CAPTAUR THE FLAGr

Developers apply techniques used in unconventional zones to conventional

How the SeaCaptau system could unlock the world’s small pools Page 8

K ON ROC team behind 3-D

Dutch shipyards group has outlined concept plans for a fleet of decommissioning-focused vessels

The printed “smart” rocks Page 12

BREAKING BONDS als and

The chemic fluids revolutionising the oilfield Page 17

Contacts 39 NEWSBASE

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

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

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

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

FACILITATE COLLABORATE INNOVATE

www.itfenergy.com

September 2016

InnovOil

page 5

A note from the Editor In early August, the UK’s National Subsea Research Initiative (NSRI) – a body whose work InnovOil has discussed on several occasions – unveiled a new roadmap for overcoming the challenges of subsea storage.

Specifically, its report concerns “Maximising Economic Recovery from Small Pool Developments,” and represents the output of a recent workshop involving innovators from across the UK and Norway. This session aimed to identify ways to stimulate investment in and encourage the development of emerging technologies which will speed up the shift from costly surface platforms to lower-cost, standalone facilities.

Commenting on the report, NSRI project director Dr Gordon Drummond noted: “Subsea storage will play an important part in the future of the industry, when there will be less need for surface platforms and ‘subsea factories’ and autonomous, low-cost production buoys are likely to become a more common solution. This will allow us to recover resources from smaller oil and gas fields and access hard-to-reach fields.”

The release of this analysis was a timely coincidence, given our choice of cover story this month. We had not long before sat down for an in-depth conversation with SeaCaptaur managing director and co-founder Alan Roberts to discuss the company’s technology – an innovative production, storage and offload system aimed specifically at unlocking small pools. The 45,000 bbl tank which adorns our front cover is an appropriate indication of the scale of the challenge – and indeed, the opportunity, if innovation can overcome it.

New subsea infrastructure will also require power – and perhaps even more of it than has been needed in the past. One Aberdeen-based firm, EC-OG, is developing a turbine to help prolong the life of batteries and equipment on the seabed and make subsea developments more economical. We explore their efforts inside.

A team from Heriot-Watt is looking even further towards the future. Over the summer we spoke with Professor Mercedes Maroto-Valer, whose work group is beginning a new research programme to 3-D print porous rock cores with embedded sensors, enabling tests on pressure, pH and fluid flow of hydrocarbons on a level of detail never seen before. Indeed, if it proves successful, in future a producer may be able understand how fluid and gas behave in its reservoir before drilling has even begun.

This month, we also examine the latest innovations from the oilfield chemicals and fluids sector.

Manufacturer AkzoNobel explains how the changing economics of the industry have led to a corresponding change in its business strategy in order to serve its customers better. We also speak to services firm TETRA Technologies about how its Innovation Group collaborates with customers, and researchers from the Universities of Houston and Chengdu investigating how graphene nanosheets can aid tertiary recovery.

All this, as well as LNG icebreakers, high-pressure water drilling, 3-D smartphone sensors and more.

We are pleased to present the September issue of InnovOil.

Andrew Dykes Editor

You can view the full NRSI report here. http://www.nsri.co.uk/uploads/160601%20-%20NSRI%20Subsea%20Storage%20Workshop%20Outputs%20FINAL.pdf

NEWSBASE

page 6

InnovOil

September 2016

High-pressure water could push drilling revolution Tim Skelton takes a look at a new high-pressure water drilling technique developed in Australia that offers a faster, cheaper and environmentally friendlier alternative to fracking

W

ATER jets have long been used in the mining and quarrying industry to cut through rocks.

The oil and gas industry, however, has tended to rely on rotary contact drilling as the go-to technology for accessing the majority of its resources. Yet with the advent of horizontal drilling, hydraulic fracturing and coal seam gas (CBM), the changing demands of unconventionals producers mean the tide may now be turning.

One company in particular has made recent headway in the space. With a licence to use patented “Vertical to Horizontal” highpressure water jetting technologies, recently established V2H International is confident that it can bring about a step-change in the economics and approach to fracturing and in-seam drilling.

Perhaps unsurprisingly, the nozzle itself was developed for the mining industry at the Australian research centre CRC-Mining, but evolved from a combination of earlier research efforts on two separate continents.

As V2H International CEO Darren Rice explained to InnovOil, the company was created in February 2016 as the result of a merger between Texas-based Zero Radius Laterals (ZRL) and Coal Bed Methane Innovations (CBMI), an Australian joint venture set up by CRC-Mining and BHP Billiton. Both had been developing Tight Radial Drilling Systems independently for the past 15 years, but the joint company formed in February of this year opened a new opportunity for innovation. “The two systems were non-competitive but highly complementary,” Rice says. “What we’ve done is effectively merged the world’s two best radial drilling water jet technologies, and the combined IP is potentially very exciting for the oil and gas industry.”

The technology itself is fairly simple. “We are just using high-pressure water. We have a highly engineered nozzle that rotates at very high speed, and a combination of the high pressure and rotation effectively separates the

Workover system

Completions system

rock, allowing us to drill (jet) a neat tunnel into the rock formation,” Rice explains.

To be able to cut through the rock efficiently, the water has to be applied at very high pressures. “We can drill up to 15,000 psi,” Rice says. “However, in the sandstones and coals that we typically work on [in Australia] we normally find that we need no more than 10,000 psi.” To reach that level of pressure, V2H is currently using high-pressure pumps from the specialist manufacturer Jetstream, based in Houston, Texas.

Lateral thinking Rice is keen to emphasise the disruptive potential of the technology. In Australia NEWSBASE

alone he points to the many thousands of existing wells that were considered exhausted, but which could potentially be reopened by going down into the vertical hole and then drilling out radially at 120 degrees in different directions, producing more hydrocarbons without increasing the well’s surface footprint.

Indeed, the V2H system allows users to drill multiple laterals of over 300 metres in length from one vertical wellbore.

His emphasis hints at the two sides of the market V2H is hoping to tap into – extending and enhancing life and recovery rates at old wells via new laterals, and for drilling new vertical wells. “The quicker you put laterals into a well, the better for the well. Laterals will significantly increase ultimate recovery from

September 2016

InnovOil

page 7

The jet is tested above ground

any given well in addition to increasing flow problems caused from formation damage, rates. It’s a true win-win technology,” he adds. which exists in every well in the world,” Rice According to V2H Australia’s website, says. “Formation damage is created the day a two systems are available: one dedicated well is drilled and as a result of introducing to workovers “for use on shallow oil wells drilling mud, water and oxygen onto a to bypass near wellbore formation damage reservoir.” in sandstone reservoirs,” and a second Using water from the formation itself may for completions “for use in degassing low go some way towards mitigating that damage. permeability coal.”

“Our preference would be to drill/jet solely Rice also points out that the relative with formation (produced) water. Since radial simplicity of the technique, and the reduction drilling only uses very low volumes of water, in the required equipment needed, should if we could use the same water that has come make it much faster and considerably cheaper out of the ground to keep the environment as to drill wells using V2H techniques than close to how it was originally, the better the using hydraulic fracturing. results. We already have filtration systems, The technology also comes with a therefore this is a very straightforward and number of potential environmental benefits, highly feasible ambition,” he added. particularly in comparison with Moreover, that could standard hydraulic fracturing radically change the economics “What we’ve techniques. For one thing, of more remote shale and fracking uses large quantities of done is effectively CBM formations. In the sand and chemicals, a need that Basin, figures from merged the world’s Permian is reduced – or even completely 2015 suggest that the average two best radial well required around 300,000 eliminated – using the water jet. drilling water jet barrels of water. Transporting Moreover, drilling using that water and frack chemicals, technologies” the new nozzle also uses far as well as dealing with the less water than comparable processing of flowback water, techniques. Increased accuracy and well makes up around 12% of the cost of onshore placement means that V2H only requires wells, based on recent EIA analysis. Greater about 5% of the volumes required by coal efficiencies in water drilling could offer a seam gas (CBM) wells. “We drill a neat method for reducing those costs and the tunnel into the formation very quickly and volume of water used dramatically. very accurately,” Rice explains. “In hydraulic fractured wells, say in a typical shale Unconventional business model formation, you could be using anywhere Another advantage of drilling instead of from 1.5 million gallons to 6 million gallons fracturing is that the new unit can be used [7-27 million litres] of water. With our Radial with a considerably greater degree of accuracy Drilling System we would typically use only in the areas it penetrates. “When a well is 1,000 gallons [4,500 litres] to drill three fractured there is little control over where laterals. There really is no comparison; it uses the fractures take place,” Rice continues. such low volumes of water.”

“We drill/jet laterals with precision [to an V2H says that in an ideal situation, it accuracy of within 10 cm], which is likely to would prefer the drill to be operated using yield a better result and also be safer from an only repurposed formation water removed environmental perspective.” during the dewatering of the well. “The Given wider environmental concerns (in oil and gas industry is very aware of the Australia and globally), the level of accuracy NEWSBASE

achievable compared to fracking means that there is a substantially reduced risk of drilling too close to a water table or an aquifer and risking contamination.

With research and trials completed, the technology is now ready for the market.

V2H’s Australian arm is already beginning to roll it out on a commercial basis. It has to date been touted as an alternative and competitor to fracking, and the initial focus has been on the Australian industry, where drilling is mostly concentrated on coal seams and sandstone. But Rice is confident that the technology could be used just as effectively to access all forms of unconventional oil and gas.

There may also be other wider potential applications. “In addition to recovering more oil or gas from any given well, radial drilling could solve multiple oilfield problems such as water and gas coning, [fine particle] migration and sand production,” he says.

“Given the low cost and rapid deployment, there are many situations where laterals are a great alternative to current technologies and methods.”

Rice says that the drill will be equally at home in the North American shale gas industry as in Australia, without the need for any major technical adjustments. In fact, he believes the technology can find an application in every oil and gas- producing region in the world – and V2H International has plans for them all.

The company recently secured a threeyear contract with Queensland-based gas company WestSide and is in negotiations with major oil and gas producers in both Australia and in North America. “We are in the process of setting up V2H USA and V2H Canada, two countries that between them have more than one million wells,” Rice says.

“We are actively looking for partners in these and other regions of the world to assist with the commercial deployment. We recently completed a tremendously successful training well in West Texas with our Australian service provider, Nitschke Energy Services, where we drilled 13 laterals.”

Although shale producers across the world have made extensive efficiency gains and cost reductions in light of lower prices, the next great technological transformation may prove harder to find. Yet if V2H’s technology lives up to its claims, it may be a good place to start. n

page 8

InnovOil

September 2016

SeaCaptaur: solving big problems in Small Pools

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

“T

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

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

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

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

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

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

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

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

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

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

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

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

InnovOil

September 2016

page 9

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

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

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

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

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

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

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

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

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

NEWSBASE

Conventional processing occurs within the SPAR main compartment, dimensions 8.4 x 8.4 x 16 m high

Stabilised crude oil is stored in subsea tank, 65,000 bbl.

page 10

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

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

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

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

InnovOil

and extending production life, rather that up-sizing.

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

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

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

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

September 2016

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

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

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

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

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

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

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

Annual Technical Conference and Exhibition 26–28 September 2016 • Dubai World Trade Centre • Dubai, UAE • www.spe.org/atce/2016

Channelling knowledge.

Connecting the world.

See you in

26–28 September 2016

Updates after 3 September 2015 may not be reflected

Society of Petroleum Engineers

page 12

InnovOil

Smart rocks play transformative role

September 2016

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

F

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

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

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

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

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

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

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

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

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

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

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

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

These sensors can measure and report on a NEWSBASE

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

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

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

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

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

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

September 2016

InnovOil

page 13

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

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

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

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

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

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

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

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

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

fundamental level you can optimise them,” she added.

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

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

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

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

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

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

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

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

InnovOil

page 14

On the radar

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

Flake out Boiling or exposure to UV rays in daylight are the most common ways of disinfecting water in which there is a risk of harmful microbes.

However, both processes are time-consuming and require fuel input.

A new innovation from the US Department of Energy’s SLAC National Accelerator Laboratory and Stanford University could change this. Researchers have devised a nanostructured device, about half the size of a postage stamp, which can disinfect water faster than the UV method and using the visible part of the solar spectrum.

In a paper published in Nature Nanotechnology, sunlight falling on the little device triggered the formation of hydrogen

peroxide and other disinfecting chemicals which killed more than 99.999% of bacteria in just 20 minutes. When this was complete, the chemicals dissipated, leaving pure water.

The device uses “nanoflakes” of molybdenum disulphide that are stacked on edge on top of glass, and topped with a thin layer of copper.

The compound is usually used as a lubricant, but in this nano-application it works as a photocatalyst, alongside the copper, to produce reactive oxygen species such as hydrogen peroxide – killing bacteria in the water.

It will not work with chemical pollutants, but in tests has managed to kill three strains of bacteria. More experiments will be required to evaluate eventual real-world applications.

Slick sense As sensor technology becomes cheaper and more complex, it is increasingly moving into homes and businesses. One example is Walabot, a 3-D sensor designed for consumer DIY which allows users to see up to 4 inches (10cm) through concrete and drywall with their smartphone.

The magnetic sensor can be clipped onto the back of an Android device and has multiple

September 2016

Thread simple Researchers at Massachusetts’ Tufts University have succeeded in creating nano-scale sensors, electronics and microfluidics which can be woven into natural and synthetic fibres. The resulting “smart threads” have been used in medical sutures to gather tissue and diagnostic information.

The threads can then transmit the data wirelessly to a smartphone or computer, all in real time.

The hope is that such a system could enable further developments in wearable technology and medical diagnostic devices.

Conductive threads are a number of chemical and physical sensing materials which could collect data such as pressure, stress, tissue strain, temperature, pH and glucose levels, all of which can be used to determine such things as how a wound is healing, whether infection is emerging, or whether the body’s chemistry is out of balance.

Sameer Sonsukale, director of the interdisciplinary Nano Lab in the Department of Electrical and Computer Engineering at Tufts School of Engineering One, and one of the paper’s co-authors, stated: “We think thread-based devices could potentially be used as smart sutures for surgical implants, smart bandages to monitor wound healing, or integrated with textile or fabric as personalised health monitors and point-of-care diagnostics.”

sensing modes to display plastic and metal piping, wires and studs, their exact depth and even movement behind walls.

The product of 3-D sensor firm Vayyar Imaging, Walabot can also be used to enhance other applications which could benefit from sensing, such as collision detection in drones and cars, or movement tracking.

The company is also

NEWSBASE

encouraging developers to create their own sensing apps using the technology. Vayyar Imaging CEO and co-founder Raviv Melamed said: “Walabot makes highly sophisticated imaging technology approachable, affordable and usable for everyone. We can’t wait to see what other kinds of applications makers and curious inventors around the world will create for Walabot.”

September 2016

InnovOil

Medical microbots Here at InnovOil we rarely tire of microbot-related news.

Most recently, a team from the Ecole Polytechnique Fédérale de Lausanne (EPFL) unveiled a raft of new medical microbot designs, as well as a corresponding test platform.

In a paper published in Nature Communications, EPFL scientist Selman Sakar and Hen-Wei Huang and Bradley Nelson of the Swiss Federal Institute of Technology in Zurich (ETHZ) detailed how they built an integrated manipulation platform that can remotely control the robots’ mobility with electromagnetic fields, and cause them to shape-shift using heat.

page 15

Their designs are made of “biocompatible hydrogel and magnetic nanoparticles,” meaning they are flexible and do not have any motors. Instead, the magnetic nanoparticles are manipulated when an electromagnetic field is applied, allowing the robots to move and swim.

Further tests will be required before these can be used in realworld medical applications – for example, the team do not yet know if they could cause any side-effects in the human body – but if successful, they could be used to deliver drugs or even perform surgical procedures.

Quest for tribofilm A new paper in Nature, authored by a team from the US’ Argonne National Laboratory, has described the discovery of a self-healing, diamond-like carbon (DLC) nanofilm.

Generated using the heat and pressure of an internal combustion engine, the new tribofilm – a film that forms between moving surfaces – could enable the design of more efficient and durable engines.

Argonne Distinguished Fellow Ali Erdemir, who led the team, stated: “We have developed many types of diamond-like carbon coatings of our own, but we’ve never found one that generates itself by breaking down the molecules of the lubricating oil and can actually regenerate the tribofilm as it is worn away.”

The discovery was made when Erdemir and Osman Levent Eryilmaz investigated the effects of coating a steel ring with a catalytically active nanocoating, which then underwent high pressure and heat using a base oil without the additives of normal lubricants.

Following the experiment, the ring was intact, but with an odd blackish deposit on the contact area.

Further experiments, led by postdoctoral researcher Giovanni Ramirez, revealed that multiple types of catalytic coatings can yield

Argonne researchers, from left, Subramanian Sankaranarayanan, Badri Narayanan, Ali Erdemir, Giovanni Ramirez and Osman Levent Eryilmaz. Picture: Wes Agresta DLC tribofilms. The experiments showed that the coatings interact with the oil molecules to create the DLC film, which adheres to the metal surfaces. When the tribofilm is worn away, the catalyst in the coating is re-exposed to the oil, causing the catalysis to restart and develop new layers of tribofilm.

The process is self-regulating, keeping the film at consistent thickness. Tests suggested that the DLC tribofilm reduced friction by 25 to 40%, and reduced wear to “unmeasurable” values.

Further investigation revealed the NEWSBASE

mechanics by which this worked: the nanocomposite coatings were stripping hydrogen atoms from the hydrocarbon chains of the lubricating oil, then breaking the chains down into smaller segments. The smaller chains then joined together under pressure to create the DLC tribofilm.

The hope is that the team’s innovation could reduce the need for expensive coatings, and the need to replace them once they are depleted.

They also believe that this could reduce the need for anti-friction and anti-wear additives in oil, which can damage catalytic converters.

Precision engineered control valves for critical subsea and topside applications

VALVES

Relief Valves l Check Valves l Manual Valves l Filters l

Directional Valves Solenoid Valves l Manifolds l Excess Flow Valves l l

www bisvalves co uk l

l

l

Tried Tested Trusted l

l

Units 17-23, Kingfisher Park, Collingwood Road, West Moors, Wimborne, Dorset, BH21 6US United Kingdom

T: +44 (0)1202 896322 E: salesadmin@bisvalves.co.uk

InnovOil

September 2016

page 17

CHEMICALS & FLUIDS SPECIAL SUPPLEMENT Pages 17-23

NOBEL INTENTIONS AkzoNobel on where to turn in a downturn Page 18

NANO-EOR

Graphene nanosheets can improve recovery rates Page 20

TETE-A-TETRA

The TETRA Innovation Group on collaborative development Page 22

NEWSBASE

InnovOil

page 18

AkzoNobel explains how it is supporting oilfield service customers in tough times

U

NLESS you have spent the past two years on a deserted island without access to any form of news, there is no denying that the industry has made a dramatic shift.

Remember the good ol’ days when everyone was printing money at a US$100+ per barrel oil price? High-value innovation was thriving and the sky was the limit. For obvious reasons that has all changed – and so have industry providers.

AkzoNobel is embracing that change.

Instead of solely focusing on the most advanced solutions for niche challenges and applications, the majority of the company’s efforts today are aimed at fine-tuning its product range and optimising its supply chain to align with the demand for more costeffective oilfield products.

“But,” notes global marketing manager for Oilfield Applications Jeroen Pul, “We haven’t lost our high-tech edge; we have just changed our focus to best serve our customers in the current environment.”

A new reality, a new attitude Market outlooks and oil price predictions change more frequently than the direction of the wind. Even though the general consensus is that the market has bottomed out, it will likely take a long time before things “get back to normal” – if they ever do. Everyone has a healthy obsession with following the oil price, the key leading indicator for our industry.

But nowadays, quips Pul, “if we had a penny for every time we got asked what will happen with the market, we would have a record year!” The uncomfortable truth is that few have a clue.

Realising it needed to adapt to these new market conditions, Pul says that AkzoNobel has transformed itself into a more flexible supplier in every sense of the word. By

CHEMICALS & FLUIDS Figure 1: Film-forming corrosion inhibitors

Figure 2: Armohib CI-5174 inhibition performance

Corrosion rate (mm/year)

Where to turn in a downturn

September 2016

Xxxxx

listening and adjusting to what its customers expect, he notes that “we want to make sure we are seen as a partner in both boom and bust periods. Because when everyone has bad cards it is up to the players to make the difference.”

As ever, price is a key differentiator. A big change in how the company operated was needed, he says, because for many years it had “a reputation for being really good, but also expensive.” In the past, many factors drove price – one of the largest of which was full plant capacity. Since then, the company has added substantial manufacturing capacity at key locations in Houston and Sweden and adopted a competitive mind-set at the same time. “When a customer calls us today they may be surprised about what we can offer and the co-operative conversation they will have,” adds sales manager for oilfield EMEIA Adrian Zuberbühler. “Luckily, it is relatively easy to fix a problem you have created yourself.”

Scale is king Given that most service companies are looking for the ultimate cost/performance NEWSBASE

solution, “cheap” is not always the way to go. It might offer initial cost benefits, but one rarely gets rewarded with superior performance – the old saying applies that “If you pay peanuts, you get monkeys.”

The wiser decision is to go with a trusted supplier, and one of the biggest players in the game. With AkzoNobel’s unmatched manufacturing capacity in fatty amines and related ethoxylates, it believes there is no one in the industry more capable of producing high-quality, field-proven products at the best possible cost.

Specifically, when it comes to corrosion inhibitors in the famed Armohib range, “We have specific solutions at the best price out there for every level of performance need and job sophistication,” Zuberbühler adds.

For example, for higher-end performance, AkzoNobel supplies imidazolines such as Armohib CI-219, offering excellent oilfield corrosion inhibition performance in many different formulations. Imidazolines are very effective film-forming amines and their solubility can be modified by neutralisation with different organic acids.

September 2016

InnovOil

page 19

CHEMICALS & FLUIDS Figure 3: Armohib CI-5174 inhibition performance under shear stress

Corrosion rate (mm/year)

proposition and strategy, because no customer would want a forward integrated supplier competing with them.”

Although it only plays a small role early on in the oilfield value chain, AkzoNobel’s chemistry skills are essential ingredients for its oilfield customers to run a productive and profitable business. “It is really our capability as ‘molecule benders’ that gives us our competitive edge,” he adds. “We leave the formulation and application up to our customers.”

The polyamidoamine-imidazolines it of Manchester, focused on the fundamental provides, such as Armohib CI-41, on the understanding of how film-forming corrosion other hand are more economical and efficient inhibitors work (see Fig 1). products that can be formulated to work in “What’s interesting is that even though both oil and water phases. They show high we have been selling corrosion inhibitors for film persistency against the attack of corrosive decades and they’re a well-integrated part of fluids. the oilfield production process, we still don’t Measured by production capacity, really know for sure how our chemistry reacts AkzoNobel is the global leader in fatty with oilfield steel casings and pipelines in amines. It offers a broad portfolio of fatty the presence of complex aqueous/crude oil acids, providing different alkyl chain lengths formulations,” Pul explains. and solubility characteristics, and clients “For example, what are the structurecan choose between coco, oleic (animal function relationships that mediate or vegetable origin) and tallow, as well as adsorption and lead to inhibition of individual fractions of these. corrosion processes on carbon It also offers ethoxylated steel surfaces? AkzoNobel “We are beginning is studying these processes versions of these fatty amines.

Compared to imidazolines through sophisticated to better they form somewhat weaker and computational understand the experiments films. However, fatty amines are chemistry through our fundamentals very economical and used in corrosion partnership with many oilfield applications. For of corrosion in the University’s School of example, diamines (Duomeen Materials. With this dedicated oilfields” T) and ethoxylated diamines academic research in hand (Ethoduomeen T/22) are we are beginning to better effective refinery corrosion inhibitors. understand the fundamentals of corrosion in In addition, there are corrosion inhibitors oilfields and we are looking forward to using with a very specific function, such as this knowledge to develop improved, nextArmohib CI-5174 – a poly-amine for CO2generation product,” he said. and H2S corrosion with a lower foam profile than standard type fatty acid imidazoline and Essential ingredients only coco benzalkonium chloride actives. It also Even in the good times – but especially in offers far better brine stability than standard the bad times – people are always looking to corrosion inhibitors (see Figs 2 and 3). dip in someone else’s profit pool. According Besides a huge production capacity, to Pul, AkzoNobel Surface Chemistry “made AkzoNobel is also making new ground in a strategic decision not to do this and focus the development of corrosion inhibition strictly on supplying chemistry ingredients technology, through its own chemistry to oil service companies around the world. experts and a partnership with the University This is a really important part of our value NEWSBASE

Working together is winning together “Being competitive on pricing and not competing with our customers are ‘hygiene factors’ to us,” explains Pul. At the end of the day, what pays the bills for service company customers is getting the job done effectively – this is why the company sees its value proposition as first and foremost aimed at helping them to deliver world-class productivity consistently.

Its portfolio of products with advanced functionalities allows customers to select the solution that best fits their specific needs in any drilling, production, stimulation or cementing oilfield application. In addition, AkzoNobel has a long track record of partnering with customers to work on exclusive innovations for specific challenges, for example on extreme performance requirements or reducing the environmental impact of oilfield operations – creating new formulations based on its core belief of “winning together.”

Whether the market is up or down, AkzoNobel believes that its chemistry capabilities can offer customers the headwind they need to win. Not yet convinced?

Zuberbühler is not shy to put his money where his mouth is and is offering readers an additional 5% discount on top of an already competitive list price for any new customers or additional business with current ones just to proof his point. “I expect to get a lot of calls and emails following this golden ticket opportunity,” he says. n Contact: Adrian Zuberbühler,

Sales Manager Oilfield EMEIA Tel: +41 41 469 6948 Email: adrian.zuberbuehler@akzonobel.com Web: www.akzonobel.com/oilfield

page 20

InnovOil

September 2016

CHEMICALS & FLUIDS

New nanofluid raises EOR expectations

Researchers at the University of Houston and Petroleum University in Chengdu have developed a new nanofluid for use in EOR, with some heady results

W

ITH new drilling slowing down dramatically, more will have to be made of old wells.

Beyond secondary recovery using water flooding, however, enhanced oil recovery (EOR) techniques tend to take over, and making such procedures cheaper will be vital to ensuring output in the next few years.

Some academic efforts have recently borne fruit.

Researchers at the University of Houston (UH) have recently published a paper describing “a nanotechnology-based solution” which could increase tertiary oil recovery by 15%, and reduce the amount of additional fluid pumped downhole. Best of all for beleaguered shale producers, its investors say it can be deployed “at low cost.”

Two-faced The researchers’ paper, published in June in the Proceedings of the National Academy of Sciences, argues that graphene-based Janus amphiphilic nanosheets can match and outperform conventional chemical and other nanotechnology solutions.

So-called Janus particles possess two or more physical properties, allowing different types of chemistry to occur on the same particle: in the case of these nanosheets, that means both hydrophobic and hydrophilic qualities. In a press statement, co-author and UH graduate student Dan Luo explained that when fluid meets with the brine/oil mixture in the reservoir, the nanosheets in the fluid spontaneously go to the interface, reducing interfacial tension and aiding oil flow towards the production well.

Because of its Janus and amphiphilic qualities, in certain conditions the nanosheetbased fluid also forms a strong elastic and recoverable film at the oil and water interface, instead of forming an emulsion.

M D Anderson Chair professor of physics Zhifeng Ren, the paper’s lead author, explained the current understanding of the process via email, commenting: “Our speculation is that the amphiphilic nature

5.00µm

Graphene nanosheets seen through TEM imaging makes the surfactant able to only stay at the interface of water and oil when both are present at the same time, even though it can uniformly distribute in either water or oil.”

In tests, it has been fairly effective. Ren highlighted that existing nanofluids used for tertiary recovery shift less than 5% of the remaining oil in place when used at a 0.01% concentration. At the same concentration, experiments with the group’s nanosheet show recoveries of 15% – comparable to existing chemical methods and three times more efficient than rival nanofluids.

NEWSBASE

That improvement in efficiency permits the same (or greater) amount of oil recovery with one third the amount of fluid – a major saving on fluid purchasing, logistics and pumping volume, though the team has not calculated any direct cost comparisons.

From an environmental standpoint, as the authors note, it also reduces the concentrations of polymers, surfactants and other fluids used downhole. Indeed, the authors note: “We anticipate that this work will bring simple nanofluid

InnovOil

September 2016

page 21

CHEMICALS & FLUIDS Zhifeng Ren, professor of physics at the University of Houston, describes a low-cost, nanosheet-based solution which could increase tertiary oil recovery by 15%

flooding at low concentration to the stage of oilfield practice, which could result in oil being recovered in a more environmentally friendly and cost-effective manner.”

Beyond the initial tests, Ren confirmed that higher concentrations of the fluid could raise recovery rates even higher, “but higher concentrations would mean higher cost owing to more usage of the surfactant.”

Coming soon The research is a joint effort between Luo and fellow UH graduate student Yuan Liu, principal investigator at the Texas Center for Superconductivity at UH, and Zhifeng Ren, as well as researchers Feng Wang and Feng Cao, and UH professor of Chemical and Biomolecular Engineering Richard C Willson.

Other authors, from China’s Southwest

When it comes to finding sweet spots in your data, do you....

Trust your eyes ?

Horizontal well targeting fractures in Eagle Ford Shale

Seismic Section

Petroleum University in Chengdu, include Jingyi Zhu, Xiaogang Li and Zhaozhong Yang.

According to Ren, the team is now working on a commercial product. The hope is that they can “scale up the surfactant and foster collaboration with oil companies.”

If it can be made commercially, it is likely to pique the interest of producers across the globe, especially Chinese producers in basins such as Daqing, where water flooding has been used for decades to shore up output, but which have recently offered diminishing returns. Indeed, in 2014 Daqing was put at the centre of a push to develop new polymers, surfactants and other EOR avenues. It may now be time to extend those efforts to include nanotechnology.

Ren’s scope remains larger still than China: he concludes bombastically that “our hope is to apply it to all the wells worldwide.” n

Interested to see what we can do with your data ?

Contact us for a trial of our unique Drilling and Exploration & Development optimisation workflows that are changing the way we drill wells and explore and produce our resources.  New Improved Resource Recovery workflows increase recovery from conventional and unconventional reservoirs or mining resources.

No seismic faults identified or predicted from Reflectivity data:

‘hit and miss’ fracture development drilling !

Or trust technology ?

 New Well & Mine Screening & Planning workflows reduce drilling & mining risks and costs and allow to optimise well & mine placements within the resource area.

For more information, watch our interview at URTeC (http://youtu.be/y2i2Ej7UPnk) or read our interview with the Innovation and Emerging Science/Technology Group of AAPG (http://www.aapg.org/publications/blogs/learn/article/articleid/ 30845), or simply contact us:

OPPtimal Resource Solutions Pty Ltd Address: Email: Web: Tel./Fax:

Fault identification: multiple seismic faults penetrated by well:

targeted fracture development possible !

NEWSBASE

PO Box 225, Wembley WA6913, Australia info@OPPtimal.com www.OPPtimal.com +61 (8) 9287 1028

page 22

InnovOil

September 2016

CHEMICALS & FLUIDS

A collaborative arrangement TETRA Technologies explains how the collaborative approach of the TETRA Innovation Group (TIG) can help to overcome customer challenges

A

S oil and gas industry operations become more complex and costly, TETRA believes that greater collaboration in developing new technologies and innovations is key to solving common challenges.

Technology development is a central component of the corporate strategy of the company, which prides itself in developing innovative solutions to meet the needs of the onshore and offshore energy markets. Despite many advances in technology over the past decade, new challenges arise every day, focusing the drive to innovate and develop new technologies.

TETRA is a geographically diversified oil and gas services company, focused on completion fluids and associated products and services, water management, frac flowback, production well testing, offshore rig cooling, compression services and equipment, and selected offshore services including well plugging and abandonment, decommissioning, and diving.

With decades of experience in scientific testing, skills and collective knowledge, TETRA offers customised, tailored solutions to address the challenging environment faced by oil and gas producers. Its focus is to provide specialised solutions that improve quality, safety and productivity to help customers navigate an increasingly regulated world. “For us,” says global VP for sales and marketing, Barry Donaldson, “success is partnering with our customers in order to achieve their business objectives.”

This partnership is achieved via a dedicated innovation unit. The TETRA Innovation Group comprises industryleading experts employing the latest technology and methodologies – meaning customers get the most innovative and cost-effective solutions. The team members

have in-depth knowledge of their fields and their customers’ business needs, and have experience in meeting both international and local regulations for a broad spectrum of industries.

Evolving technologies There are many challenges involved in creating an innovative environment.

But as Donaldson adds, “At TETRA this is our specialty! We work side by side with our customers to understand their challenges and develop new technologies to address them wherever you are in the world.” The implications of those NEWSBASE

technologies are significant: in the energy sector, process innovation can have a dramatic impact, not just on the bottom line of individual companies, but also on national economies.

TETRA uses agile project management methodology within the “stage-gate” framework to evaluate and accelerate its response to customer challenges. Agile development involves the use of shorttermed delivery cycles called sprints.

Each cycle is a series of iterative steps: develop, test, obtain feedback and revise.

The use of sprints allows product design to be adapted

September 2016

InnovOil

page 23

CHEMICALS & FLUIDS

in real-time to match the job requirements.

Automated blending and sampling/ measurement can happen in real-time at rates of up to 110 bbl per minute.

TETRA’s Automated Blending Solution can save its customers money by reducing the overall costs associated with water needed for fracturing operation.

as needed and ultimately reduces overall development time.

The entire organisation is aligned to deliver customer solutions, and some of its newly released innovations are generating impressive results.

Onshore technology innovations One of the biggest challenges facing the onshore oil and gas industry today is water management. The ability to recycle produced water and minimise the use of fresh water can improve operator profitability and promote water conservation. Delivering consistent water quality and volumes as per the frac design is key to the successful completion of a frac job. Any changes in water quality, volumes or rates during the stimulation job may lead to screen outs or unpredictable stimulation results.

Operators must match the characteristics

of the source water with the frac treatments used. Produced water reflects reservoir geology, which in some cases means the water is incompatible with a frac treatment. TETRA’s automated blending solution takes the guesswork out of combining produced water and fresh water into a consistent blend needed for fracing. Blending source water with fresh or brackish water with a lower chloride content is a simple and cost-effective solution to water quality and consistency issues. Moreover, optimal blending must be done in real-time during the frac job to ensure consistency is maintained during the entire operation.

Controlled automated blending technology provides on-the-fly, real-time measurements of input and output water quality. The technology continually measures output quality as well as the quality of the input water stream (i.e., conductivity related to chloride content), making adjustments NEWSBASE

Deepwater – not a problem Jointly developed in collaboration with a major Gulf of Mexico operator at a cost of more than US$1.5 million, TETRA CS NeptuneTM is an innovative, high-density completion fluid, free of solids, zinc and formates. TETRA CS Neptune has been specifically developed for deepwater and complex high-pressure wells that require heavy clear brine solutions to control well pressure during the completion phase.

Moreover, TETRA CS Neptune addresses the environmental challenges facing offshore oil producers seeking an alternative to zinc brines.

The first application of TETRA CS Neptune was for a Gulf of Mexico operator on an ultra-deepwater completion. The job required a 14.5 pound per gallon (ppg) completion brine for use at a well depth of over 30,000 feet (9,150 m) in a water depth over 7,200 feet (2,200 m) and a seabed temperature of 39°F (3.8°C).

The lower completions were installed successfully, with TETRA CS Neptune performing as designed after a 15,000-psi BOP test, encountering no issues with true crystallisation temperature (TCT) or PCT throughout the well.

You can access more information on TETRA CS Neptune, via the website at www. tetratec.com/csneptune.

Collaboration is the key TETRA has built a reputation in the industry for recognising that energy producers require new and innovative solutions that deliver unparalleled performance. By listening to its customers, the TETRA Innovation Group has a deep understanding of their needs, enabling it to develop a pipeline of new technology innovations. n Contact: Barry Donaldson,

Vice President Global Sales and Marketing Tel: (+1) 281 364 2254 Email: bdonaldson@tetratec.com Web: www.tetratec.com

September 2016

InnovOil

The hub of the matter

page 25

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

P

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

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

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

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

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

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

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

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

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

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

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

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

The overtrawlable SPH template can hold up to three turbines

NEWSBASE

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

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

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

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

page 26

InnovOil

DSME’s icebreaking LNG carrier nears completion

September 2016

Sophie Davies reports on DSME’s latest Arc7 ice-class LNG carrier, designed to navigate the icebound waters of the Russian Arctic and an innovation central to the success of the country’s Yamal LNG plant

T

HE world’s first icebreaking LNG carrier, known as Christophe de Margerie, is reportedly nearing completion at the Daewoo Shipbuilding & Marine Engineering (DSME) yard in South Korea, and is set to herald a new era in LNG shipping.

The 172,000 cubic metre vessel, the first of 15 such tankers currently being built at the yard, is on order by Russian maritime shipping company Sovcomflot. It will be used to ship gas from the giant US$26.9 billion Yamal LNG project, located in the northeastern section of the Siberian Yamal Peninsula.

Yamal LNG is being developed by Russia’s largest gas producer Novatek, which has a 60% stake in the project. France’s Total and China’s CNPC each also hold 20% stakes in the project. The project includes the construction of a plant capable of producing 16.5 million tonnes of LNG per year. It will consist of three trains, each with between 5 and 5.5 million tonnes of annual capacity, and each with its own LNG storage facilities.

The first Yamal train is expected to launch commercially in 2017.

A class of their own Yamal’s Sabetta terminal is located in the far north of the Russian Arctic, meaning that the new carriers will need to be able to proceed through thick ice all year round.

The waters around Sabetta are ice-covered for approximately 300 days a year and temperatures of -40°C are not unusual during the winter months.

The new carriers being developed by DSME, each costing some US$300 million, will be able to operate in temperatures as low as -50°C, owing to new anti-freezing technology.

DSME, which was not available for

NEWSBASE

comment when contacted by NewsBase, began experimenting with anti-freezing technology in 2008 using a 10-tonne oil tanker, according to local reports.

It is the particularly challenging Arctic conditions that Yamal presents that make the new breed of icebreaking LNG carriers necessary. There are already 11 ice-class LNG carriers in service; however, none are capable of moving through the thickness of ice necessary to service Yamal.

The existing vessels – all of which are ice-class 1A or Arc4 – can only handle ice thicknesses up to 0.8 metres. However, with an enforced steel hull 25% thicker than equally-sized non ice-class vessels, forward and aft ice belts and three sets of Azipod propellers offering a total output of 45 MW, the new vessels in the DSME build-out are designed to pass continually through ice up to 2.1 metres thick. This should also ensure they do not need separate icebreaker escorts.

In addition, they all use double-acting ship (DAS) technology, which allows iceclass vessels to proceed in both open seas

September 2016

InnovOil

page 27

Left: DSME’s first Arc7 ice-breaking LNG carrier for Yamal LNG, Christophe de Margerie, was launched in Jan ‘16

Main Image: Sovcomflot where ice is thin, and in full icebreaking mode. DAS was developed by Aker Arctic in 2002 for two oil tankers – Tempera and Mastera – used to transport oil from Russia’s Primorsk terminal in the Baltic Sea. The design means that when in full icebreaker mode, the ship will travel stern-first.

The new vessels will also use six Wärtsilä dual-fuel engines, which are capable of handling the extremities in engine load variations that can occur when a ship passes through thick ice.

Safer passage The ships will open up “a new trade in the Far East and European markets, with the ships capable of transiting the Northeast Passage across the north of Russia,” Krispen Atkinson, principal maritime analyst at IHS Markit, told NewsBase. They are being constructed to the highest ice class capable, known as Arc7, he added.

Indeed, these carriers may well be the key to the success of the entire scheme. They are “really important” for the Yamal project,

independent LNG consultant Andy Flower explained to NewsBase. However, they will only be used here in the Russian Arctic, as no other LNG project requires technology for such extreme conditions, he noted.

Arc7-class tankers are also being used by state-run Gazprom Neft to provide year-round oil transportation from the Novoportovskoye oil and gas condensate field on the Yamal Peninsula. The Russian producer announced in March it had launched the first of seven such vessels, which will each be able to carry up to 270,000 barrels of crude, more than twice the capacity of the Arc5 icebreakers currently employed by the company.

Gazprom Neft concluded that this was the only viable means of exploiting Novoportovskoye’s resources, given that the field is located some 700 km from the nearest liquids pipeline.

Regarding Yamal LNG, Flower cautioned that the economics of the vessels themselves would raise some doubts, as the shipping cost to Europe will be very high. Coupled

NEWSBASE

with any delays in the construction schedule – the last of the 15 icebreaking vessels is currently scheduled for completion by early 2020, but the first has already been delayed by months – and the whole project outlook becomes even more questionable.

However, the LNG carriers are the “only way that Novatek can get the gas out” of Yamal, Flower added.

The only alternative would be to sell the gas in Russia via Gazprom’s network of pipelines. But Gazprom would either charge a transit tariff or deny access to its grid altogether on the basis that the Yamal scheme posed a threat to its market share.

Even if Novatek were able to transport the gas via pipeline easily, demand in Russia for gas is fairly weak at the moment, given the country’s ongoing economic downturn.

With sea and gas trials ongoing during July, Christophe de Margerie is expected to depart South Korea in October to embark on its first tests in icebound conditions, before final delivery to Sovcomflot in January 2017. n

page 28

InnovOil

September 2016

COMMENTARY

Lines between conventional and unconventional blur As developers apply techniques used in unconventional zones to conventional plays the once-distinct lines between the two areas of production will vanish, writes Kevin Godier

A

SLOW fusing of the lines between the conventional and unconventional oil and gas arenas has been underlined by a new study, which suggests that the tight conventional domain will increasingly benefit from the export of lower-cost technology used to unlock unconventional zones.

Released in mid-July by data and business research provider IHS Markit Energy, the report examines how unconventional technologies can be applied to the redevelopment of conventional wells in the top 39 established US tight conventional plays, where major shale plays are also being developed.

Entitled Horizontal Drilling in US Tight Conventional Plays, the study is timely, coming as it does during a period when the global oil industry is seeking and deploying all forms of cost-cutting in a push to implement the efficiencies and savings that can ensure its survival through a period of lowered oil prices that has lasted for over two years.

The report draws its findings from an assessment of nearly 46,000 US horizontal wells completed between 2010 and 2015, 10% of which were in tight conventional plays. Identifying formations being drilled today, plus opportunities in other formations with little drilling to date, the report concludes that “there are significant potential benefits of applying some of the same drilling and completion techniques that have been used so successfully in the US shale oil plays to increase recovery in these tight, US conventional plays,” according to IHS’ director of North America well and production content, Steve Trammel.

The key plays identified in the study

that have the greatest potential to leverage horizontal technologies include the Williston, Powder River and Denver basins in the Rocky Mountain region, the Permian Basin and Eagle Ford play fairways in Texas, and the mid-continent region, including the Anadarko Basin.

Low costs, good infrastructure The average global recovery factor for a conventional oil reservoir is 34%, leaving slightly less than two-thirds of the oil in the ground, according to IHS Markit.

However, a number of tight conventional oil reservoirs show recovery factors of 15% or even less (tight conventional reservoirs are defined as those within the 0.01 to 2.0 millidarcy permeability range, which have typically tended to be sub-commercial in the conventional domain).

The good news is that the average initial potential (IP) test rates for the leading tight conventional plays that it scrutinised compare favourably with the IPs of established shale oil plays. In addition, said Trammel, leveraging unconventional technologies should prove attractive to operators because the overall breakeven costs to develop these projects are much lower and delivery infrastructure is already in place.

Trammel noted that: “These tight conventional resources are in reservoirs with older vertical wells that can be re-entered by horizontal drilling. The rock properties do not require the size and cost of a hydraulic frack job needed for an unconventional zone, and therefore these are much more economic for operators in the current low oil price environment.”

Another bonus, he stressed, is that the use of horizontal wells to test tight conventional NEWSBASE

plays further in several US oil zones has resulted in the establishment of stacked plays with major resource potential. “The plays in the Rocky Mountain region, in particular,” he said, “have the majority of the highestranking tight conventional plays of those we studied in our IHS Markit Energy report, but tight conventional plays in Texas, including the Permian Basin and Eagle Ford fairway, also fared well, in terms of potential for redevelopment.” Trammel also flagged up the potential for shallow conventional plays to offer opportunities for operators to leverage unconventional technologies in the ongoing oil price environment.

What next One key inference from the report is the gradual dwindling of the characteristics that have come to define and separate conventional and unconventional oil reservoirs. This trend is bolstered in other respects, including the reality that not all shales are found in unconventional reservoirs.

Indeed, a majority act as overburdens and seals to conventional reservoirs.

September 2016

InnovOil

page 29

COMMENTARY The Devonian shales of the Appalachian Basin have produced gas since the early 20th century. Today, there are more than 20,000 horizontal wells.

But in terms of the methods developed well and reservoir performances for all types to extract oil and gas from a virtually of asset structures. impermeable source rock, it is clearer In oil markets where the sheer pace than ever that these can be extended to and scope of change from the “shale gale” more profitably develop marginal, nearover the past decade have dramatically conventional reservoirs that would not have challenged hydrocarbons explorers and been considered commercially service companies of all sizes, viable two decades ago. an obvious conclusion is that “The study is InnovOil believes that skill sets that can determine timely, coming as the new approaches to tap more rocks with production potential it does during a at a relatively low cost will resources and to understand better the nature of highperiod when the continue to be in huge demand. quality conventional reservoirs oil prices have stretched global oil industry Low will continue to see the light of operational practices for is seeking and day in the years ahead, driven unconventional reservoirs to by economic necessities and the limit, but the upside is that deploying all technical opportunities arising such reservoirs are now able to forms of from the cross-pollination of compete with conventional and cost-cutting” ideas. near-conventional reservoirs for Where geophysicists what remains a limited pool of work on problems and challenges linked development dollars. to unconventional reservoirs, the results Of course, if energy prices climb again over of that research will spill over into more the next decade or two, other unconventional precise understanding of conventional and sources may make the jump into large-scale near-conventional reservoirs, resulting in a viability. The candidates here would have to concomitant ability to model and optimise include oil shale; methane hydrates; advanced NEWSBASE

biofuels derived from algae or waste, and fuels distilled directly from carbon dioxide (CO2) in the air using sunlight.

For the near term, however, industry eyes will be sharply focused upon the growing potential of tight zones which are bypass zones within a conventional reservoir, and which have traditionally been passed over as being sub-commercial without some type of stimulation. The advent of unconventional extended lateral drilling and multi-stage hydraulic fracturing has reduced the technical difficulty and cost of such operations, transforming some of these zones into palpable commercial prospects.

Given that this technology can extract fresh resources without any accompanying environmental cost or scarring of the landscape, InnovOil forecasts a big future for this interface between the conventional and the unconventional. Even a decade or two from now, conventional-unconventional distinctions may have become outdated, with the “unconventional” moniker being used to describe the world’s more speculative energy resources. n

2016

16 & 17 NOVEMBER 2016 - HAMBURG MESSE, HAMBURG The leading event for the German tank storage industry

REGISTER TO ATTEND TODAY Meet with suppliers, source the latest products and keep up-to-date with industry trends.

www.tankstoragegermany.com

Official port supporter

Show supporters ®

Serving the tank storage community globally

EXPOEUROPE 28 - 30 MARCH 2017 - AHOY, ROTTERDAM

MIDDLE EAST AFRICA 26 & 27 APRIL 2017 - DUBAI WORLD TRADE CENTRE, UAE

Register now gg www.tankstoragegermany.com

CHINA NOVEMBER 2017 - SHANGHAI WORLD EXPO, CHINA

Organised by

September 2016

InnovOil

Damen goes for decom with new concepts

page 31

The Dutch shipyards group has outlined concept plans for a fleet of decommissioning-focused vessels

N

ETHERLANDS-BASED Damen Shipyards Group is targeting the North Sea decommissioning sector with its concept design for a specialised vessel conceived by one of its undergraduate interns.

The Damen Decommissioning Series will focus on three areas of oil and gas commissioning – topside decommissioning, offshore platform removal and subsea cleanup and removal.

The concept was based on research by Rotterdam Mainport University marine technology undergraduate Justin Rietveld, who was asked to explore niche markets in the decommissioning sector that would be suited to new rig designs.

It has a monohull with a split stern which will be used for platform removal operations, by allowing the ship to reverse next to a jacket, where it can be ballasted to reach below the platform.

Damen claimed its vessel would be capable of decommissioning fixed platforms weighing up to 1,600 tonnes, enough to remove half of those located in the North Sea. Modular add-ons would be marketed to provide broader functionality, including one preliminary design that would handle the temporary installation of a crane or helideck.

Discussing the Group’s research manager for design & proposal offshore & transport,

Lucas Zaat, commented that: “We initiated this project because we felt that we can make a difference in this sector – and it has certainly generated some significant ideas.

The decommissioning market is close to our current activities. We are therefore planning to continue with this project and assign specialised personnel to implement it.”

Decommissioning is poised to become big business in the UK Continental Shelf (UKCS) as shipyards and other services

The vessel’s monohull design has a split stern for topside removal operations NEWSBASE

firms diversify their offering to counteract declining rig orders for producing fields.

Oil and Gas UK research published in November 2015 suggests total decommissioning expenditure will reach GBP16.9 billion (US$22.5 billion) in the period ending 2024. Spending hit a record GBP1 billion (US$1.3 billion) in 2014.

More than 250 fixed installations in the UKCS need to be decommissioned, as well as 250 subsea production systems, 3,000 pipelines and 5,000 wells.

On August 2, the UK Oil and Gas Authority (OGA) awarded four contracts worth a combined GBP6 million (US$7.98 million) for studies aimed at integrating the exploration, development and production sectors with late-life planning and decommissioning.

OGA also folded its decommissioning unit into the retitled Exploration, Production and Decommissioning (EPD) directorate on August 1, to reflect the importance of decommissioning to the “asset stewardship lifecycle”.

The OGA set a 35% cost reduction target for the sector on July 1 in its decommissioning strategy, which highlighted clarity on cost reductions, better decommissioning capabilities and guidance for stakeholders as key priorities.. n

page 32

InnovOil

September 2016

NEWS IN BRIEF

Woodside awards Technip subsea contract FRANCE’S Technip has won a wide-ranging subsea contract worth at least US$275 million to help Woodside Petroleum develop its Greater Enfield project offshore Western Australia, it announced in August.

Technip will assist with the management, design, engineering, procurement, installation and pre-commissioning of some of the subsea pipeline infrastructure at the project, in 340-850 metres (1,115-2,789 feet) of water, it said.

The infrastructure involved will include a carbon steel production flowline, a carbon steel water injection flowline, flexible risers and flowlines with a total length of 82.2 km.

Technip will also help with subsea structures and valves as well as the transportation and installation of a multiphase pump system.

Flexible pipes will be manufactured at Technip’s plant in Tanjung Langsat, Johor, Malaysia, while its division in Newcastle, the UK, will provide the umbilicals. Various Technip vessels will perform offshore installations, which are due for completion in 2018.

Woodside also last month awarded a more than US$300 million engineering, procurement and construction (EPC) contract to Schlumberger unit OneSubsea to help develop the same project.

OneSubsea will supply a subsea production system and a dual multi-phase boosting system to Greater Enfield, it said last week.

The scope of work includes six horizontal trees for the project’s water injection system, six multi-phase meters, a high-boost dual pump station with high-voltage motors, umbilical, topside, subsea controls and distribution, intervention and workover control systems, landing string, and installation and commissioning services.

Use of the latest technologies as well as existing FPSO infrastructure means that Woodside and partner Mitsui E&P have been able to contain the investment spend on the project at the low end of their initial guidance range, according to Woodside chief executive Peter Coleman.

This has allowed the companies to accelerate the development of previously stranded resources, he said. The first stage of construction of the Greater Enfield project is forecast to cost US$2.25 billion. n Edited by Andrew Kemp andrew.kemp@newsbase.com

Sasol considers Mozambique FSO South Africa’s Sasol is reported to be carrying out a study on the possibility of connecting its onshore liquid natural gas centre in Mozambique to a floating storage and offloading (FSO) unit, in order to process light oil from its Pande and Temane fields.

According to a report in the Notícias newspaper, Sasol is carrying out an environmental impact assessment (EIA) into the proposed development which lies off the coast of the country’s southern Inhambane province.

Sasol is the only gas producer in Mozambique, extracting reserves from Pande and Temanes and then transporting them via an 865-km pipeline to markets in Mozambique and South Africa. Earlier this year, the company began drilling a number of new wells in the region, discovering light oil.

The potential production volumes are unclear and the firm is considering two options. Should volumes be low, oil could be transported by road. If they prove more substantial, a sea pipeline has been proposed, running parallel to existing gas infrastructure to the FSO. A fifth unit will be installed at the gas processing plant at Temane will be installed to handle the crude.

The environmental study is being carried out Environmental Resources Management and Impacto, with the latter stating that a draft of the study would be presented to the public later this month.

“Stakeholders will be notified of the availability of the draft scoping report and the date, time and venue of public meetings through announcements in the local newspaper, the radio (in Portuguese and Xitswa), and formal invitations,” it continued.

Sasol is keen to diversify its output from the fields, stating in May that the area “reaffirms Mozambique as the central point of Sasol sub-Saharan oil and gas strategy and provides a platform from which socioeconomic growth will be driven”.

The South African company began drilling on its Production Sharing Agreement (PSA) in the East African country in May, with a plan to drill 13 production wells. The first phase of work has been estimated to cost US$1.4 billion.

In October 2015, Sasol was invited to negotiate a licence on the PT5-C area, which covered 3,012 square km, close to its existing Pande and Temane acreage n Edited by Ed Reed edreed@newsbase.com

NEWSBASE

September 2016

InnovOil

page 33

NEWS IN BRIEF

Zhang Gaoli and Vladimir Putin sign their names on the Power of Siberia pipeline

Africa Oil plans FEED work for 2017 in Kenya Africa Oil received US$439.4 million in the second quarter of the year, improving its cash position substantially, as the company acknowledged in its recent results, announced on August 12. The cash was paid to the Canadian-listed company by Maersk Oil for a 50% stake in three blocks in Kenya and separate areas in Ethiopia.

Another US$75 million may be available to Africa Oil on confirmation of resources, with Maersk also having committed to carrying up to US$405 million of additional costs, dependent on certain resources being achieved and the timing of first oil.

Front-end engineering and design (FEED) studies are expected to be launched on the upstream and pipeline components of its work in Kenya, in the South Lokichar Basin, Africa Oil said. A pipeline would have the potential to include other oil production from bordering countries, it noted. A joint development agreement is expected to be signed on a pipeline in the third quarter.

The company also noted an independent assessment of contingent resources in Block 10BB and Block 13T in Kenya. The 2C unrisked resource was estimated at 766 million barrels, as of May, it said, up by 24% - or 150 million barrels – from 2014. The company said this covered 754 million barrels of development pending resource and 12 million barrels of “development unclarified”.

Drilling will restart in the South Lokichar

Basin in the fourth quarter. Initially, this will cover four wells, with the potential to add a further four. The first two wells are expected to be on the Etete and Erut prospects, it said, in the north of the basin. Also under consideration are plans to target the undrilled flanks of existing discoveries at Ngamia and Amosing.

The Cheptuket-1 well was drilled in Block 12A and the results are being analysed, Africa Oil said. Total drilling and completion costs in the first half came to US$10.43 million, primarily on the Cheptuket-1 well and demobilising the PR Marriott 46 rig. This was a substantial reduction from the same period in 2015, from US$108.5 million.

A full tensor gravity (FTG) survey was launched in July on Block 12A, Africa Oil said, in order to provide further data on this area.

Furthermore, core analysis is being carried out on 1,100 metres from wells drilled in the South Lokichar Basin, in order to provide more information on the recovery factors of the main reservoir sands, it said. n Edited by Ed Reed edreed@newsbase.com

Amur gasprocessing plant finally being built Gazprom has awarded a contract to Stroytransgaz to prepare ground for the construction of the Amur gas-processing plant in the Svobodny district of that region, Interfax reported last week.

NEWSBASE

The plant will be used for the fractionation of the gas transported through the Power of Siberia pipeline on its way to delivery to China. It will produce methane, ethane, propane, butane, pentane-hexane fraction and helium. Purified methane from the plant will be exported to China.

The Gazprom Pererabotka Blagoveshchensk company, which has 41.2 billion rubles (US$644.5 million) in capital, was created for construction of the plant, which will have a throughput capacity of 42 billion cubic metres per year. The plant is scheduled to go into operation next year.

Facilities for 5,000 people are currently being built adjacent to the site, along with ten warehouse buildings with a total area of 33,000 square metres. The settlement will cover a total area of 72,000 square metres.

Stroytransgaz will build 45 km of track from the Ust-Pera railway to the factory site.

It will also construct a bridge over the River Bolshaya Pera, a highway overpass and two railway stations to serve the needs of the plant. The stations will have the capacity to handle 2.4 million tonnes of cargo per year.

In July of last year, Interfax reported that contractors and subcontractors subject to Western sanctions would not be used in the construction of the plant. Stroytransgaz, however, was targeted under the US regime in April of 2014. In October, Gazprom announced that a consortium consisting of German company Linde and Ufa’s NG Peton research and design institute was selected to provide equipment for the plant, winning out over a consortium of Uralmash-Izhora Group, South Korean Daelim Industries and French Air Liquide.

The plant will be the world’s largest producer of helium, churning out up to 60 million cubic metres of the gas per year.

Natural gas can consist of up to 7% helium, but the usual proportion is around 0.7%.

The gas is used in the production of MRI equipment, silicon wafer manufacturing and welding.

The helium market was worth US$700 million worldwide in 2015, according to Earth & Space Science News. It has grown more bearish in recent years, however, following the recent discovery of new reserves. As recently as 2012, the US produced 75% of the world’s helium, with 30% of it coming from the government’s Federal Helium Reserve. Since then, the US has lost control of the market, and helium supplies have gone from shortage to glut. n Edited by Joe Murphy josephm@newsbase.com

InnovOil

page 34

September 2016

NEWS IN BRIEF

SOCAR and Total strike initial deal to use sixthgeneration rig at Absheron Azerbaijan’s SOCAR and French super-major Total have reached a preliminary agreement on using the former company’s new sixthgeneration drilling rig for operations at the Absheron gas field in the Caspian Sea, Trend reported on August 4.

An unnamed source said the pair were making progress on negotiations and expected to sign the final contract after the rig’s completion, which is due later this year.

Construction on SOCAR’s sixthgeneration semi-submersible platform, which is modelled on Keppel FELS’ DSS38 M standard model, started in July 2013. It is capable of operating in up to 1,000 metres of water and can drill to a total depth of 12,000 metres. The rig’s pontoons are designed to allow transit through channels with a shallow draft of under seven metres, while its living quarters can host up to 160 crew members.

Absheron was discovered in 2011 in around 500 metres of water, some 100 km from the Azeri capital city of Baku. It is Azerbaijan’s second largest field with an estimated 350 billion cubic metres of gas plus

45 million tonnes (330 million barrels) of gas condensate in reserves.

SOCAR and Total both hold 40% stakes in the pre-development Absheron contract, alongside Engie (formerly known as GDF Suez) with 20%. The partners plan to take a final investment decision (FID) on the project in the fourth quarter of next year, before drilling starts at the first well in late-2019. Commercial production is due in 2021 and will reportedly ramp up to a peak of 7-8 bcm per year.

The field’s gas will initially be sold domestically, although SOCAR still has to reach an agreement with Total on pricing terms for these sales. The state-run oil company is thought to be pressing for a fixed rate separate from global price fluctuations, which would reduce the profits available to Total should the global supply glut ease.

At a later stage, gas from Absheron could be exported via the South Caucasus Pipeline (SCP), while condensate could be shipped via the Baku-Tbilisi-Ceyhan trunk to Turkey.

It is hoped that the field will help Azerbaijan revive flagging hydrocarbon output as yields from maturing fields like the BP-operated Azeri-Chirag-Guneshli (ACG) complex continue to decline.

Commercial gas output in Azerbaijan fell 9% year on year to 9.36 bcm during the first half of 2016, despite total production increasing by 1.2%* to 14.9 bcm because of re-injection at ACG to enhance recovery. n Edited by Joe Murphy josephm@newsbase.com

Caspian Sea AZERBAIJAN

Absheron Peninsular Bacu

Absheron Gas Field

Statoil submits US$415m Utgard development plan Statoil is moving ahead with the development of the Utgard gas and condensate discovery in the North Sea, which was first identified in 1982.

The field is scheduled to come on stream at the end of 2019, and will produce at peak around44,000 barrels of oil equivalent per day. The discovery has been considered for development on several occasions in the past, said Statoil’s senior vice president for project development, Torger Rod. Despite the current low oil price environment he said the decision was underpinned by new technology and advances in extraction that made it more viable.

“I am very pleased that we now can realise a commercial development at Utgard,” he said. “This clearly demonstrates the effects of the improvement work that has taken place in the oil and gas industry in recent years.”

The Utgard field (formerly called Alfa Sentral) holds recoverable reserves estimated at 56.4 million boe and is anticipated to cost around 3.5 billion kroner (US$415 million) to develop. Located about 21 km from the Sleipner field, it straddles the UK-Norway median line, although the majority of the reserves are on the Norwegian side.

Statoil has submitted a development plan to both the Norwegian and UK authorities.

The development will include two wells, with one drilling target on each side of the median line, although all installations and infrastructure will be located on the Norwegian side.

It will be the first Statoil development “in many years” producing resources across the median line, according to Rod. He also said the proximity of the Sleipner infrastructure was crucial in the decision-making process.

Gas and condensate will be piped through a new pipeline to the Sleipner field for processing and further transportation to the market. With a high CO2 content, the gas will also go through carbon cleaning and storage at the nearby field.

“Utgard provides new production which will be essential to further developing the Sleipner area,” Rod added. n Edited by Ryan Stevenson ryans@newsbase.com

NEWSBASE

September 2016

InnovOil

page 35

NEWS IN BRIEF

Uruguay seeks partner for regas terminal Uruguay is seeking a partner for running its first floating regasification terminal, with plans to export surplus send-out capacity to Argentina and elsewhere.

Uruguayan Energy Minister Carolina Cosse said the goal was to find a partner “before the end of the year.” She did not say which companies had expressed interest.

This will be the country’s first incursion into importing LNG, a market it turned to after getting burned in the early 2000s

by Argentina. Its neighbour reneged on a contract to sell gas by pipeline, as that country’s dwindling production brought shortages and a surge in imports.

At first, Uruguay turned to renewables to diversify energy supplies, though it now wants to back this up with gas imported to the terminal, which will have an initial 10 million cubic metres per day of send-out capacity. The LNG imports will wean the country off of an over-reliance on imported oil and local hydropower generation. The plan to install the regasification terminal has faced numerous problems, however. At first Argentina agreed to be a partner in the project, but then pulled out. Construction delays last year were then compounded by the exit of a consortium of France’s Engie and Japan’s Marubeni from the US$1.1 billion project.

The government has continued with the plans, led by Gas Sayago, the state-run company that is overseeing the project.

Last month, Gas Sayago signed a contract for the delivery of the floating terminal from Japan’s Mitsui OSK Lines (MOL), which had started construction under the previous project partners, Engie and Marubeni.

MOL is building the floating storage regasification unit (FSRU) at a shipyard in South Korea run by Daewoo Shipbuilding & Marine Engineering. The FSRU will have the largest storage tank for LNG in the world, with 263,000 cubic metres of capacity.

This will allow the terminal to supply an estimated 3 million cubic metres of output domestically, and sell most of the rest to Argentina. As more capacity is added or Argentina buys less than planned, supplies can be sold to other buyers. n Edited by Ryan Stevenson ryans@newsbase.com

Intertek invests £800,000 in corrosion and materials technology centre Intertek, a Total Quality Assurance provider, has invested a further GBP800,000 in its Manchester corrosion and materials centre to offer world-leading facilities for innovative research, consulting and testing services.

Production and Integrity Assurance (P&IA), part of Intertek Exploration and Production, announced a GBP1.2 million investment in the centre last year and has since expanded the site to 40,000 sq ft, making it one of the largest integrated materials engineering consultancy and testing facilities in the world. It has now been renamed ‘The Manchester Technology Centre’.

This latest investment has enabled P&IA to integrate its specialist consultancy, corrosion NEWSBASE

management, infrastructure, asset integrity and production chemistry facilities into one purpose-built centre of excellence, to answer increasing demand for these services worldwide.

Gareth John, Director of Consulting Services at Intertek P&IA, said that: “Investing in The Manchester Technology Centre will enhance our failure investigation, materials evaluation and testing capabilities.

This state of the art facility, with industry leading expertise and equipment under one roof, also places Intertek in an ideal position to conduct specialist investigations, including innovative research and development programmes.

In addition, it will enable us to provide superior customer service to our clients in the areas of corrosion and materials testing.”

Intertek P&IA has provided global corrosion and materials solutions for over 40 years, supporting organisations across a range of industries including chemical, pharmaceutical, power generation, oil and gas, transportation and infrastructure. n INTERTEK

page 36

InnovOil

September 2016

NEWS IN BRIEF

American Shale Oil scraps US kerogen project American Shale Oil is quietly dropping its plans to exploit oil shale – or kerogen, not to be confused with shale oil – in Colorado.

Oil shale has so far proved more challenging to develop than other unconventional resources, and the move comes as no surprise. The company is the latest to scrap plans involving federal oil shale leases in Western Colorado. American Shale Oil is owned by Total and Genie Energy. It had been developing a commercial way of producing oil shale.

However, in April Total withdrew from American Shale Oil’s project, known as Rio Blanco. At the time, American Shale Oil’s president, Claude Pupkin, attributed Total’s decision to low oil prices. “This one didn’t make the cut and at that point, while Genie was still interested in proceeding, we just didn’t have the funding and couldn’t find the funding to make it happen,” Pupkin told the Grand Junction Daily Sentinel.

American Shale Oil is currently decommissioning the project – a task that is expected to cost US$5 million – said the newspaper. Total has reportedly agreed to pay US$3 million of this.

American Shale Oil will give up its US Bureau of Land Management (BLM) oil shale lease. The company had previously anticipated starting commercial production in 2014 and producing 100,000 barrels per day by 2018, according to its website.

Other companies, including Royal Dutch Shell, have also scrapped plans to produce oil

shale in the region. Shell closed its research and development centre in Rio Blanco County in 2013. It planned to produce the oil in situ, while the kerogen was still in the ground, protecting local groundwater with a technology called “freeze wall”.

Several leases were issued in the region.

Chevron has also abandoned its project, as has ExxonMobil. The only remaining player in Colorado is Simple Oil, which is currently seeking a permit from the US Environmental Protection Agency (EPA). Simple Oil is owned by Canada’s Enirgi Group. Meanwhile, Enefit is still pursuing a kerogen project in neighbouring Utah, as is Red Leaf Resources.

The US is thought to hold the world’s largest deposits of oil shale. Development is in its infancy and it is not clear when any process will be commercially viable. The oil shale deposits found on federal land in Colorado, Utah and Wyoming contain an estimated 4.285 trillion barrels of oil in place (OIP) according to the USGS. n Edited by Anna Kachkova annak@newsbase.com

Statoil works to maintain Hammerfest To maintain production at its Hammerfest LNG plant, Norway’s Statoil has deployed a rig to drill a new injection well for CO2 and a well to replenish the plant’s natural gas intake.

Statoil said on August 9 that the newly hired Songa Enabler semi-submersible had begun drilling a new CO2 injection well on the Snohvit field in the Barents Sea.

Statoil’s Hammerfest LNG plant NEWSBASE

After that, it will drill a production well – the first to be drilled on the Snohvit field since 2007 – in order to maintain feed gas supplies for the LNG plant on Melkoya Island, near Hammerfest in north Norway. It is expected that the drilling process will last until late 2016.

Snohvit remains the world’s only LNG project that captures and stores CO2 from the well stream in a dedicated formation offshore. Statoil said that over 4 million tonnes of CO2 had been sequestered thus far, with monitoring under way in order to make sure it does not mix with the main producing reservoir.

The company said a new CO2 injection well was first planned in 2013, to replace the original injector well, as this would, over time, leak CO2 into the Snohvit field’s gas reservoir. A marine campaign carried out in the summer of 2015 included the installation of pipelines and a template for the CO2 project, which were then tied into the existing subsea facility on Snohvit.

Statoil’s asset owner representative for the project, Geir Owren, said: “Hammerfest LNG needed replenishment of gas in order to maintain the high production and capacity utilisation at the plant, while ensuring sustainable CO2 storage.”

The next big step for Hammerfest LNG, according to Statoil, is the development of its Askeladd field, which is part of the plan for the development and operation of the Snohvit licence. Askeladd is scheduled to come on stream in 2020-21 and will ensure full utilisation of the 4.1 million tonne per year capacity Hammerfest LNG export plant. n Edited by Ryan Stevenson ryans@newsbase.com

September 2016

InnovOil

page 37

NEWS IN BRIEF

McDermott, N-KOM team up in Qatar THE US’ McDermott and Qatar’s Nakilat Keppel Offshore Marine (N-KOM) signed an agreement in late July to co-operate on bidding for work in the Qatari offshore oil and gas sector.

N-KOM is a joint venture (JV) between Qatar Gas Transport Company (Nakilat) and Singapore’s Keppel Offshore & Marine formed nine years ago to build and operate a shipyard at Ras Laffan on the northeast coast. While offshore activity worldwide has experienced a prolonged slowdown as a result of low oil prices and investment cutbacks, Qatar has continued to provide a steady flow of work, with several marine oilfield developments tentatively proceeding. But competition is fierce, with state-owned Qatar Petroleum (QP) taking advantage of the changed situation to drive down costs.

The two companies said their five-year memorandum of understanding (MoU) was intended to “develop an integrated approach to projects in Qatar by leveraging [McDermott’s] proven track record in offshore [engineering, procurement, construction and installation] EPCI projects and N-KOM’s ship repair and offshore construction facility at the Erhama Bin Jaber Al Jalahma Shipyard [at Ras Laffan].”

The US firm will act as prime contractor, taking the lead on engineering, procurement and installation using vessels sourced from its global fleet, while N-KOM will serve as a subcontractor for fabrication work conducted at its Qatari base. McDermott already plays a prominent role in the country’s EPCI market and has worked on numerous offshore projects for QP. Speaking during an earnings call in July, CEO David Dickson said that while the partners were not targeting contracts on the immediate horizon, three large fields at which developments were in the front-end engineering and design (FEED) phase offered significant longer-term potential. “We see [the MoU] as a means of positioning us more strategically, so that we can really participate in what could be some significant bids coming out over this next couple of years,” he said. n Edited by Ian Simm ians@newsbase.com

Golar and Schlumberger Form OneLNG Joint Venture Golar LNG and Schlumberger today announced the creation of OneLNGSM, a joint venture to rapidly develop low cost gas reserves to LNG. The combination of Schlumberger reservoir knowledge, wellbore technologies and production management capabilities, with Golar’s low cost FLNG (Floating LNG) solution, will offer gas resource owners a faster and lower cost development thereby increasing the net present value of the resources.

Golar and Schlumberger have 51/49 ownership of the joint venture. Golar and Schlumberger have agreed an initial investment commitment to cover the estimated equity needed to develop the first project. In addition, the parties will on a project-by-project basis discuss additional debt capital as required. This future financing will take into account Golar’s FLNG intellectual property through an equitable contribution mechanism to be agreed between the parties.

Golar Vice Chairman, Tor Olav Troim said that: “Our new venture with Schlumberger provides a powerful union of their oilfield services technology and production management business, and our low cost FLNG solution. It leverages Golar’s LNG expertise, and builds upon our industry leading position as a midstream solutions provider.”

Schlumberger, President Operations, Patrick Schorn commented that: “This new joint venture is uniquely positioned to optimize the development of low cost gas reserves. The technology platform and production management capability that Schlumberger brings will enable a total system approach, leading to a simpler and fast-tracked FID process, and reliable operational execution for the benefit of the gas resource owners.”

OneLNG will be the exclusive vehicle for all projects that involve the conversion of natural gas to LNG, which require both Schlumberger Production Management services and Golar’s FLNG expertise.

After reviewing the current market opportunities where 40% of the world’s gas reserves can be classified as stranded, both NEWSBASE

parties are excited at the future prospects of OneLNG and are confident that it would conclude 5 projects within the next 5 years. n ONELNGw

Boldman develops mobile test cell Modular aluminium profile manufacturer Boldman has developed a mobile ballistic test cell to increase efficiency and reduce costs in oil and gas industry testing. The cell uses a lot of the innovations from Boldman’s existing large fixed cells, but has the added benefit of being movable, which many clients demanded as their testing locations were not always permanent.

The maximum size the of the high pressure test cell is 6m by 6m by 4m high and it will be used to test small assemblies up to 30,000psi.

The ballistic glass test cells are manufactured from Boldman’s aluminium profile system and specially manufactured safety glass, giving 360° visibility when testing oil and gas equipment. This visibility means companies testing their equipment can invite their customers to view their equipment live whilst it is under test.

The new design means that the test cell can be moved by castors attached to the individual panels or transported via crane across the workshops.

The structure of the cell is designed to withstand a strike from a ¾-inch twopart BuTech MP fitting under test up to 30,000psi. In-house testing has seen the cell withstand a 6. oz. Butec fitting travelling at speeds of up to 180 metres per second (400 m.p.h.)

The test cells are used by some of the largest oil and gas developers in offshore engineering, the high-pressure test cells are used around the world for testing offshore components under simulated extreme conditions.

The new cell technology is seen as a replacement for its heavy steel predecessor both because of vastly improved visibility and its modularity making it is easy to ship and install on-site.

The test cells were first developed in 2014 and Boldman’s test cells are being used worldwide in Angola, Malaysia, Nigeria, Norway, USA & UK. n BOLDMAN

September 2016

InnovOil

What next …?

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

If you are interested in small pools development, or if the SeaCaptaur system could be of benefit to your future production plans, contact SeaCaptaur MD Alan Roberts on +61 (04) 1234 7324 or email admin@seacaptaur.com.au To discuss how AkzoNobel can give you a competitive edge in tough times and help your company in “winning together”, speak to Adrian Zuberbühler, Sales Manager Oilfield EMEIA, on +41 41 469 6948 or email adrian.zuberbuehler@akzonobel.com For more information on the 3-D printed rock cores and tests being developed by Professor Maroto-Valer and her team at Heriot-Watt University, contact m.maroto-valer@hw.ac.uk or visit www.hw.ac.uk TETRA Technologies Innovation Group collaborates with customers to deliver impressive innovations.

To learn more about TIG, CS Neptune or TETRA’s Automated Blending Solution, contact Shari Mattern on (+1) 281 364 5078 or via smattern@tetratec.com To learn more about V2H’s water jet radial drilling technology, visit www.v2h.com.au EC-OG’s Subsea Power Hub could be transformative for the economics of subsea power developments.

For more information or to make an enquiry, contact Graceann Robertson on +44 (0)1224 933 301 or email info@ec-og.com

NEWSBASE

page 39

An asset to energy professionals

Published by vNewsBase

Bringing Bringing you you the the latest latest innovations innovations in inexploration, exploration, production production and and refining refining Issue Issue 39 22

OCEAN OF SAVINGS

FoundOcean discusses offshore cost-efficiency Page 9

RETURN OF REFRACK

A look at the companies and WORLD technologies FIRST leading the US trend HIL testing with Page 12 Marine Cybernetics

™

SE

ing refin 16 20 and ™ June g ction u d efinin o nd r April 2015 n, pr hed by ™ on a ratio ti Publis c E lo u S p d o S B A ex ning n, pr ns in NtiEoW g d refi ly 2016 ratiS oE d by hein SBA nova n an Ju efinin eExWplo o r ti Pubslis t d c N in n ™ te du 2015 na ond sby ber tihe , pro SE the la g valis Decem uctio S B A ation you finin innoPub prod N E Wxplor ™ test ging and re ber 2015 tion, hed by in e Brin g the la pSloB rAaS E ction Publis ons x in u Novem u e n d o ti fi y 43 n, pro Issue nova nd re th 2015 ons inN E W ging ratio on a st in oPvubalistihed by ti Brin lo Mon n te c p u la in x e S st prod e 42 ENT g you the ons in E W S B A S E e late OsuM g tion, N ovati DECVIsELOPnM refinin you th plora , inregin st inn Published by in ex E ging R duction and September 2015 ing DEA solutioonsandBmro 44 e late Brin tionsN E W S B A S th a T TEnIO v u n o ti & o ue , pro P BEra Iss ora gy inn blished by o d refi 2015 b t e 40 ti B in n a s su a g ll Is te co on Pu st ITHlook at® Brin Augu the la 15 Wplo ducti in ex Page tionBsA S E WeBetafib tion, pro 39 g you a v in o Issue g n S r iera Brin sun’s ex ospiflo test in N E W ON

26 Page

Issue

XX

ns intee X Ho grading eSie pme de eria h ml asgeneeetic Pag oil-frm bact respon stea ine spill 2 rb

ER. POWPER. a in DEE w er n

20 Page

34

u the ing yo Bring Issue

12 Page

™

to 27

30

Zn

ed by

Publish

ing you Bring

November

Zn

the latest

ations innov

Page

ing you

ation, in explor

ction produ

g and refinin2014

Issue

Issue

Page

Zn

Page

13

IN FROM COLD

THE rature from Cold Tempe s sifiers Demult Oil ServiceXX p.

Clarian

CAPT ue Iss

Produc cy experts p. XX Efficien

w

™

FLAG

g and refinin2014

Page

10

ed by

Publish

ing you

Bring

g and refinin2014 July

Issue

,

ration

Page

ED & TEST 100 TRIEDPaar’s Callisto Anton 10 Page ER WAT BWA IN THE s from

April

ing

Bring Issue

Twenty

latest you the

ations

innov

March

One

d Heateenrtre ont f18e n-contacPt &A? dfrifom re ofR, NEW a bAitDrilliPangge’sthno futu e EA G IT Is AB NEW Y NGES don PLASM LLEK’s Neil Gor xx Page CHbsAea U ld Su the fie s survey

Issue

NEWECTION s DIR system DDO GEM from Page

Page

8

6

4 Page

5

24

E SENS SIXTHense’s flare

Lumas ring system monito Page

14

Publish

ed by

ations innov

Clari Services’ AT® SURFTRE aids back flow10 THE ALL IN ISTRY CHEM

ction produ

g and refinin2014

Bring Issue

and uction n, prod oratio in expl

ED G

g refinin

P from

CORESTIONS QUE goes subsea

the latest

ations

innov

ction

, produ

ration

in explo

4

June 201

d -SV tion an produc ation, explorPage xx tions in innova e latest th u yo g Bringin ture Issue 23 mperafrom ColdiaTe fiers ices l ecmulsi Serv XX De ea Sp SubS p. nt Oil Claria

Nineteen

NCED ION ct ENHA n proje DUCT TriGe PRO

G NDIN EXTE S LIMIT from

sk Oil’s Maer Page

rill™ Gas Viscod VA Oil & OMNO Page

June

tions vaby nohed inblis Pu latest

September

Society The Royal try talks tions of Chemis innova oilfield 4 Page

™

g and refinin2014

il InnovO 4 Page

g refinin

May 2014

ns CONTROL ER AND cal Solutio POW ering Umbili

LINEfrom Atlas PIPElaying pipe IN THE ated

Oceane 8 Page

Copco

™

Autom 14 Page

Publish

™

ed by

sBase

vNew

the latest

ations

innov

ction

, produ

ration

in explo

g and refinin2014

January 18 Issue

13IO ge S MPaIS ORING MONIT bsea ing you

Bring

g and refinin2014

e Zetechtics HeR Seaa systems from

January

Page

9

CORES

Subse

TION ar Su Moduloring fromQUEurSQ&A withn O tio Monit berg Producperts gs y ex p. XX nc on K Efficie

CORESTIONeaS QUE goes subs

“Following the article we al experienced increased level of nu n A 4 1 0 2 interest in our products and we can directly attribute significant new customer enquiries to the publication.”

S UP SURF’ ant Oil Page

ation, in explor

sBase

vNew

Page 6

ing you

the latest

27

NG A NE awardLIGHTI LIFELI gy’sPATH TICAL N PhotoSyner TAC MATIO g LIGHT winnin ER FOR’s AccuLite 18 Page NSF Trican ting system TRA DOW cemen WIN at Bronswerk’s 8 g Page Page

u the ng yo Bringi

™

ed by

Issue

ction produ

Page

23

Page

Publish

ing you Bring

ation, in explor

24

The ery Syst Deliv SeaBotix from6

Page

4

ations innov

the latest

E SPONS RErized RAPID Containe em

Issue

AGR’s 6

2

A look act coolin comp

ing you Bring

May

Modular ng from Monitori rg Kongsbe 10

Think achievemen latest

Atlasile drilli mob Page

ed by

Publish

™

g and refinin2014

N MISSIO ORING MONITSubsea

2014

7

AWARD SON SEATank Maths’ t

THE FECT R PEREDATO PR Copco’s ng rig

xx Page

the latest

9

ction produ

ation, in explor

ia

, produ

ration

in explo

g and refinin2014

Page

4

ations innov

as s sp e ec t

n ar ion bongedi8sc ission S uC Well- entionCould 14 1 billLees Pa comm ent interv tion extra6 Tomes and de uipm UP pric Page SUIT diving eq revolu

ction

DHL’s s solution

innoby latePustblished

Page

L G INTE ERIN re GATHiQx™ softwa

™

sBase

vNew

4

July 201

™

Page

Biocide 11

ed by

7

L VITAISTICS LOGintegrated

Pumps SLD and Power

Page

Publish

Page

il asks InnovO industry drilling 4

Page

™

Yokogaconcep Plant

Se CORE Issu TIONthe QUES

testin netics HIL e Cyber Marin

Heriot EOR at sity Univer 6

2014

re o n and refining e futuprriodnucgtio ? n,o AVs thorat ioit X on Are Unssinseextplm Page vatioa 8

rly t Vigilan see clea wa’s t

Page

V ort SEPAESHIN The U Valep Alex Grant, UNLO SE ing OM NN A T I P ll T 2 S R 2 ri F E A D N LD otor ID R ericze Product ndtific nal’TIN sHTEITCAOg ieManager RAPCLine in m tio ontain Stem terna ance drill The ry SysIn orm Well Drilling, Copco DeliveSeaBotipxerfAtlas N from Page

WORLD FIRSTg with

ber Novem

Need Nord-L ces No introdu tening For Retigh

ER POWPLY SUP

ing you Bring

™

De

yne ME OF Teled otiG xA S SeaBPage 6 RONE f 10

TighTriTy secuock

2

Dyfo s from rope n Brido

cia ls

EERING PION PECTIVE Watt PERS

Page

ON AE WIRrm Bristar

UND OF SO from SPEEDThe UV-SVP Valeport 8 Page

25

4

201 cember

Page

Tranter design plate

25 and refining Issue ction produ

in explo

ations

innov

August

A clos 4

ed by

sBase

g refinin

g and refinin2014

& trace n track Services eld ly chai Supp Swire Oilfi from

Publish

vNew

the latest

ation, in explor

2014 at ONS ch-ch er look

™

22

ations innov

26

Page

u the ing yo Bring

The s safety proces

17

w

ction produ

ation, in explor

Page

Issue

February

5

TY SAFE INGhts its new NEER cation E highlig ENGI qualifi IChem

Schlum Geo Quanta

lD

ations innov

4

ALISTIC ces they service introdu PHOTORE bergerreservoir geolog

c

ed by

the latest

Page

PIPELINEN

ECTIO on PROT ring corrosi ne Oil Monito Teledy Gas with and PageX

Publish

ing you Bring

6 Page

ction

, produ

ration

in explo

DOF

TING HEA UP ’s innovative

Z28 n

e& URE THE Captur h Carbonable Scottis e roundt Storag

CORES TION with QUES Our Q&A tion

Zn

Issue

ations

innov

ing c Drill TITAN22 or nal’s Scientifi ng mot Internatioance drilli perform

Zn

O nd n 9 Mge CLE ICIENTenZtn arn logy Page ONanBd DiameLwoearLi Prof. Pa ep le N OFseismo EFrFsupplemduction s GE e an n tO F ENSE’s de TURAis 6 n Ou les pro ? e K e T Page C now RE R is O mak nership Well-S ntih vatio o inno F nat the e mentat ck ROB Optim part RtEio intervlution volu eOvaRncesusbsea equdip ligeHfferticLuiexn-2cy N X ok ies and A im lo o r M Page A e slastuteandstiquned at an from ZPages 11 5 plte Uo r rev H pan gies o m 8 g e 6 t a e la n 1 s’ co n n H r-drilli eTh n Th ioio iceedct Page on US n se Page techninolo ro uctnce ielde V Serv sp Dolitw specti atioLa oilfa g the 10 y RO in inpinptetinmais al w inde in ice afolvtirSon Page y Uti in-lan em lead idtoebo ma o26 rategies p l theech 6 olra SdO em roP Page Va Page st anlla su fuptunre aofSw trend hNsaAsF e TineSc g co 17 ith nu l Rm A 12 ge w b e Pa nc ge n G a a e’ Pa riti icatio INergavEn Maha ain e on th LLin Ete s unlock anfields?

Halgfw Ha mmun suzosNtobel’sCtaOkNTaRmrOKn ie ge 26 co SK ngsb ity deTEb Sog xx ol RaTnn Page d-poronductiv inAEg Lfreo o Pa Ak XalPate bch 18 ICSS16 FLi w on Q&loAw ulat nftiu in Page ’s lsus ses lo ing reea Page tO e Suarlbs ENSEstim conve uted FINUSA’s Distrrcibe™ GP ic Sou Seism

vNew

the latest

Twenty

g Profilin Subsea

28

December

of future s the itoring?

Are UAV t mon Page X asse

29

Bring

2014

the latest

“The article was great and we received Dour first sales lead as a result of the Oarticle ND today.”

F SOU ed by

Publish

™ 1

page

November

4 ber 201

ction produ

and uction ain d onThe, chpro lorati fr-choangesm in exp ing you Bring

2014

™

g Iss rintin s ga 3-D p HowZn e oil and g chan8 Issue

ed by

Publish

™

sBase

sE nUR YO ATio at innov SERVIC Novem latest u the Zn ng yo SHING UNLEA BriGADRnMEONgiOFESZn A TITAN shed by Publi couueld29

Zn

™

1 page

™

DR I SP LL EC I IA N UN PaLgSUPPLG/S es EME E C SP O 9- NT ISM EC N 23 INS IA V ID IC E PaL SUP EN ge PLE T s 1 ME IO 1- NT I N oi 27 NSI A lf DE L S sp ie e

xx Page

ning d refi ion an January 2015 roduct on, p lorati p ex in

ns by tio ishednova teblst in laPu u the ng yo taBringi al Annu

Issue

ti plora s in ex

hed by ovation

Publis

inn latest u the ing yo Bring

31

13 Pages

an hore dOce s Foun sses off discu fficiency e ts co 9

™

IAL and Production Inc. ECExploration Ou prooFset OiL yFueintau-dtrepeth-loteokchant oalos gy SUBSEA SP VERSATILLEE C cawnoAinnilte-gribtyigandd&eA agralpples VETHhIe vLBV Issue

ING Ho adingOur Q ig Da e AT hB is N I degr ria hweitlp im ts p E O V S ime cte ponse O a M IP R S b r NT V U e es ak OF + PR EEALU DpEPTbH spill12r CTRL a snOCEVAINNGS HIF T n e s e g A o a E S S IC Hoop P THrwayK’sRIEsuG URCE ND No BLITZ PS SinEg ISMaarten deing could DING THE SO AN A 17 Page

Page 6

A nempletioAOsLOGY Mark Hempton, N YNE co u EiDCsHh Manager of Exploration and ED… TOfPlTr vEeLD i T r M O a R ro st F late on, pTechnology at Shell International

Issue

on st arch rese nhse late n New missioT roductiotion p misa AUV X opti tegies Page stra

™

Co onsvin by isc Page 16 e la fining ati ou th Published SE ing y innov and re July 2016 SBA ™ g Bring ction latest NEW e th by refinin ed UdReYpth ilrautison, produ you 37 C g Publish n and June 2015 R Issue in io g E G Brin aexuptlo rs roduct AMnFin shN AatLioaaLntttIN einy’s necto ration, p ing n 36 fi v k lo re o by Issue n o p and lonsolisnheUMdRAeSaPEcCfoJMortions in ex st in h 2015 ction Marc e late JohPnub Pb produ ou th seutelacteehsnst6oloreingmnyoovvaa24l tion, ing y plora fining g ury Pagehed by Bring Pearc s in ex Page 14 you thm n and re ary20201515 g lis o n ti ub in P 44 ary bru Issue Feru ductio Feb Bring innova 30

tu

1 Page

ThinkTank Maths’ latest achievement

Also available on your tablet

™

y

uld es co tteri er ba hole Hott er down t w o n p ipme equ

E E -2 DDO systems NLVSUPPeLs 11 from g IA COGEM PageP8EC Pa S UN w

“The article on Kongsberg Maritime’s Munin AUV is excellent!”

™

e

ING TIONYu S E US GR T EYETQ ERIE iL IyOetants BA TINTEO t asse o a k asn oluti NON N A loogrc ity w oil- FRIC TIO ’

S AL

E NEW IONINSID DIRECTION NTMENT 7

AWARD SEASON

Page 4

SE

Pa l sup int ge ple e s 1 men g 3- t in ri 27 sid t

SBA

Pa upp h SP ge lem e EC s 9 en m IA L S -21 t insiica De l UP s PL EM EN T

NEW

Dyform Bristar ropes from Bridon

Page 7

Page 20

™

SBA

ON A WIRE

Siemens’ magnetic oil-free steam turbine

™

NEW

November April 2015 2014

NONFRICTION

™

hed by Publis

™ ™

NEWSBASE

Published by

2

UME M VOL IMU MAX latest

8

ING TRAC g TO WIN o’s taggin

Page 10

T RUN TES with

etics HIL testing Cybern Marine Page

T IOLE RAV ULT water atg UV tion purifica Page

THe iNTOe blu UK reports

GOiNG peR ive Dee Fugro’s ROVs Page

Subseaindustry on the Page

2

9

7

Trican’s frac fluids Page

Tracerc logy techno 12

4

Page

Page 4

ersity Univxx

STEoD100 ICTE D T& LIS thellist rvice AIE ’s Ca ucares RETR se Pa Page

TOrgerAnintotrxxnod r geology PHO be Page rvoi Schluma Geo rese ATER 17 Page

EW A IN TH from BW ides Biocxx Page

Y TuR ST ceN 21 Y l field buO ’s margina s ABTOG ment solution develop Page

19

INE PIPELTION TECcorrosion PROrin g ne Oil

il Inno4vO Page

asks InnovOilindustry drilling

Scot e roun PE Heriot Storag EOR at

Quant

innovat

ito Gas CORE IONS Monwith Teledy and Pa geX QUEST the

G FLA HE ur & G ptEEeRIN E UREPTIO CaN V CAPtisTh Carbon leSPECTI att dtabR W 4 Page

5

FETY INGhtSsAits new EER highlig cation ENeGICIN hemE ty qualifi Th s safe proces 10 Page

L G INTE ERIN are GATHiQx ™ softw Copco

AGER’s NEfrom Atlas 6 e LI g E PpiIPPag pe layin SE INtoTH mated H SEN

Au

Page 14

TROnsL CON ND lic Solutio ER gAUm bi al POW neerin Ocea8 Page

SIXTsense’s flarem Luma oring syste monit Page 14

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

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

“We were pleased with the

immediate interest that our article attracted.”

“The article on Kongsberg Oxford Catalysts Group Maritime’s Munin AUV is excellent” Mark Hampton, Manager of Exploration and Technology, Shell Exploration and Production Inc. Published by

e-mail: sales@innovoil.co.uk Phone: +44 (0) 131 478 7000 www.innovoil.co.uk