Innovoil 2015 Annual Review

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December 2015 ™

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Bringing you the latest innovations in exploration, production and refining

Bringing you the latest innovations in exploration, production and refining

Bringing you the latest innovations in exploration, production and refining

Bringing you the latest innovations in exploration, production and refining

Issue 40

Issue 39

Issue XX

Issue 37

December 2015

BETTER WITH BIO

We look at Cosun’s Betafib® viscosifier Page 16

MERCURY FALLING

November 2015

Month 2015

NONFRICTION

September 2015

POWER. DEEPER.

Siemens’ magnetic oil-free steam turbine

A new era in completion fluiDs hAs arriveD …

An in-depth look at Nautilus subsea connectors Page 6

Page 20

Page 14

Johnson Matthey’s PURASPECJM technology for mercury removal Page 24

OCEAN OF SAVINGS

FoundOcean discusses offshore cost-efficiency

SEISMIC SHIFT Page 18

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CTRL + PRNT

How 3-D printing could change oil and gas

Page 9

Prof. Maarten de Hoop on how deep learning could revolutionise seismology

C MIE EIS SID /ESMENT2IN3 G INUPPL 9ILLIAL S ages DR SPEC P

RETURN OF REFRACK

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Utility ROV Services’ unique subsea equipment Page 6

Our supplement tackles production efficiency innovations

sustainable supply

AkzoNobel’s take on the future of the chemical oilfield

Pages 11-25

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Down tools

CLEAN AND EFFICIENT

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Page 12

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S ALE IONINSID NETMEN-T27 E NVUPPL 11 COCIAL Sages UN SPE P

A look at the companies and technologies leading the US trend

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Bringing you the latest innovations in exploration, production and refining

Bringing you the latest innovations in exploration, production and refining

Bringing you the latest innovations in exploration, production and refining

Bringing you the latest innovations in exploration, production and refining

Issue 36

Issue 35

Issue 34

Issue 33

August 2015

TOP TECHNOLOGY FROM TELEDYNE Page 12

July 2015

Longer sheLf Life

June 2015

Future-prooF

Cutting-edge CArriers

Pages 13 to 27

Page 24

An in-depth look at asset integrity and technology

How EOR is helping Statoil reach 60% recovery Page 12

naiLing down hammerhead™ A closer look at Baker Hughes’ ultradeepwater completion system

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ICSS from Kongsberg Maritime Page 16

Flexible Friend

Page 10

Bronswerk’s Flexplate is a new approach to heat exchangers

an awesome wave

HUMAN OR ROBOT?

CONTROLLING AN FPSO

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Laser-drilling from ZerLux

Page 6

Page 26

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Heat and ligHt

GPUSA’s Distributed Seismic Source™

The latest advances in inspection and maintenance

Japanese shipbuilders are poised to see a renaissance thanks to LNG

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FINDING THE SOURCE

Halfwave’s ART Scan tool for in-line inspection

Page 10

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T EN EM PL UP S IAL EC SP

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stimulating debate e sid

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Could unconventional technologies unlock an extra 141 billion barrels in low-productivity fields?

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Bringing you the latest innovations in exploration, production and refining

Bringing you the latest innovations in exploration, production and refining

Issue 32

Issue 31

Issue 30

March 2015

big deal

Is AgustaWestland’s AW609 TiltRotor the future of offshore transport?

neW tool kit

J2 Subsea’s 4 Port ROV Tool Changer Page 13

ith t W en W itm 33 noCru page e re se ™

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FULL-TILT

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April 2015

A Win-Win For the industry?

DNV GL’s exciting new project explores floating wind-powered water injection

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May 2015

SUBSEA SPECIAL

February2015 2015 February Issue 30

VERSATILE VEHICLE

Our Q&A grapples with Big Data

The vLBV from Teledyne SeaBotix

Page xx

Page 30

Page 6

Bringing you the latest innovations in exploration, production and refining Issue 27

September 2014

SURF’S UP Clariant Oil Services’ SURFTREAT® flowback aids Page 10

ALL IN THE CHEMISTRY

The Royal Society of Chemistry talks oilfield innovations Page 4

EXTENDING LIMITS

IN THE PIPELINE

Our Q&A tackles pipeline efficiency and inspection Page 12

Shared idealS

JOINT VENTURE

ASK THE EXPERTS

Radyne’s Merlin system speeds up field joint coating

Page xx

Page 8

Page 17

Tom Leeson discusses low prices and decommissioning

Enhancing collaboration and communication with nuVa

Careful abandon

OTC HERE

A look ahead to OTC’s latest innovation event Page 22

Page xx

ITH T W EN W ITM 34 NOCRU page e e E R s

a bit different

Is GA Drilling’s non-contact PLASMABIT the future of P&A? Page xx

Subsea Q&A

SUIT UP

Heated diving equipment from entro

Viscodrill™ from OMNOVA Oil & Gas Page 8

TRACING TO WIN

Tracerco’s tagging technology Page 12

Page 18

NEW YEAR, NEW CHALLENGES Subsea UK’s Neil Gordon surveys the field

2015 Annual Page 4

a DNV GL company

Third-party testing of BOP software A modern Blow-Out Preventer (BOP) relies on a sophisticated redundant computer system to achieve desired performance and safety. The scope of BOP-HIL testing from Marine Cybernetics is to verify correct functionality according to rules and regulations, user requirements, and to detect hidden software errors and design flaws in the BOP system software.

Marine Cybernetics secures your needs and ensures your future!

For more information on our annual seminars, see www.marinecyb.com

safe software – safe operations

SC ANPARTNER REKL AMEBYR Å

Inspired – Dedicated – Reliable

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Annual 2015

page 3

Inside A note from the Editor

Contacts:

First oil from Edvard Grieg 6

Media Director Ryan Stevenson ryans@newsbase.com

GAIL pipeline monitoring

7

Just a phase?

8

SkyTech’s the limit

9

With pipeline monitoring now being done by drones and sensors, GAIL (India) is looking at satellite technology

Media Sales Manager Charles Villiers Email: charlesv@newsbase.com Media Sales Manager Riley Samuda RileyS@InnovOil.co.uk

A new form of solid carbon

Executive Editor summary

Innovation priorities in a low-price environment

67%

Andrew Dykes In any industry, a cyclical downturn forces senior andrewd@newsbase.com management of companies to make painful decisions across most aspects of their operations. In capital-intensive industries such as upstream oil and gas, some of the toughest decisions revolve around companies’ investment in technology innovation.

NewsBase Limited Centrum House, 108-114 Dundas Street Edinburgh EH3 5DQ Dropping or postponing a project today may help the bottom line in the short term, but it could impair the company’s ability to find and exploit new reserves of oil and

Business leaders in the industry are not shying away from making tough decisions, judging by the large number of major development projects being

Oil and gas innovation, in other words, is far from frozen even in today’s difficult environment.

A more cost-focused mindset is leading those responsible for

gas tomorrow. Downturn or no, the reality remains that there is no more ‘easy oil’ – future reserves will be harder to reach and ever more expensive to get out of the ground.

shelved — and as this study finds, the technology innovation initiatives being put on ice. Cost reduction and improved operating efficiency are the watchwords for oil and gas innovation today.

technology innovation in their companies to become more resourceful. This is evidenced, for example, in their greater openness toward collaboration with other firms, and their receptiveness to crossover technologies from other industries.

Phone: +44 (0)131 478 7000 www.newsbase.com www.innovoil.co.uk Senior management and boards of upstream companies have not had to make such choices for many

The digital revolution is coming to technology leaders’ aid,

years, as oil prices have – with a couple of brief interludes – been

however. In particular, the rapid maturation of advanced data

on an upward trajectory since the turn of the century. That trend has been rudely interrupted, and although difficult to forecast, expectations are that the industry is settling in for a sustained period of comparatively low oil prices.

technologies is having an impact.

These technologies are generally not prohibitive in cost to deploy and offer near-term gains in efficiency improvement. Digital and data underpin some of the key initiatives technology leaders are hoping to push in their firms.

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

of oil and gas executives believe that the oil price will stay between $50 and $70 a barrel in the next year.

How will this oil price impact their innovation priorities?

0 Now, the primary drivers of innovation investment are:

76%

46%

Say oil price instability has led them to slow down or halt most innovation initiatives

Improving operational efficiency

36% Reducing costs

35% Improving access to potential reserves

Deployment of new technologies remains a major innovation challenge:

56%

70% say the challenges involved with the real-world deployment of new technologies is a key barrier to innovation

2016: Global outlook

10

On the Radar

16

Predictions, projects and innovations

say data collection and analytics will be important to their innovation efforts over the next two years

Most of what we're embracing in data capabilities are coming from outside, developed for other industries. There are fantastic companies and universities who have data analytics that are opening our eyes to what might be possible.

David Eyton, Group Head of Technology, BP

6

Lloyd’s Register Energy’s Oil and Gas Technology Radar report

THE BEST OF 2015 19 Win-Win

20

Looking into the IRIS

24

Lateral thinking

28

Easy does it

30

Utility players

32

Wind-powered water injection

Behind Norwegian EOR research

Laser drilling from ZerLux

Enhanced oil sand extraction ™

Utility ROV’s pecialist subsea equipment

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December 2015 ™

2015 Annual

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in exploration,

Bringing you the latest innovations

production and refining

in exploration, production

Bringing you the latest innovations

and refining

in exploration, production

Issue 39

December 2015

Teledyne Seabotix profiles its options

and refining September 2015

Issue 37

Month 2015

A new era in completion fluiDs hAs arriveD …

An in-depth look at Nautilus subsea connectors

Siemens’ magnetic oil-free steam turbine

Page 16

and refining

in exploration, production

POWER. DEEPER.

NONFRICTION BETTER WITH BIO

Bringing you the latest innovations

Issue XX

November 2015

Issue 40

We look at® Cosun’s Betafib viscosifier

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Big power, little package 34

and refining in exploration, production

ations Bringing you the latest innov

Page 14

Page 6

Page 20

MERCURY FALLING

Johnson Matthey’s PURASPECJM technology for mercury removal

Page 24

OCEAN OF SAVINGS

CTRL + PRNTcould How 3-D printing change oil and gas

FoundOcean discusses offshore cost-efficiency

SEISMIC SHIFT de Hoop on

A look at the companies and technologies leading the US trend

Page 18

™ Published by

in exploration, production

Published by

NEWSBASE

Bringing you the latest innovations

and refining

Bringing you the latest innovations

and refining

in exploration, production

Page 24

Page 12

hammerhead™ naiLing down at Baker Hughes’ ultradeepwater

Zn

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A closer look completion system

Page 12

Page 9

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The proven potential microbial EOR Page 14

stimulating debate technologies unlock an ide t ins en 6 Lem -2 pp 11 L su s ge cia spe Pa

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Could unconventional in low-productivity fields? extra 141 billion barrels Page 6

in exploration, production

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Issue 32

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Bringing you the latest innovations

in exploration, production

and refining March 2015

ith t W en W tme 33 noCruipag re see ™

Looking for a breakthrough 40

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in exploration, production

SUBSEA SPECIAL

Issue 30

and refining 2015 February2015 February Issue 30

VERSATILE VEHICLE

Issue 31

The vLBV from Teledyne SeaBotix

Our Q&A grapples with Big Data

Is AgustaWestland’s AW609 TiltRotor the future of offshore transport?

DNV GL’s exciting water injection floating wind-powered

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big deal

FULL-TILT

t inpplem13-2 secial su ges as spe Pa

the industry?

A Win-Win For new project explores

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™ ™ Published by

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HUMAN OR ROBOT?

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GPUSA’s Distributed Seismic Source™

GA Drilling’s non-contact PLASMABIT

Friend FlexibleFlexplate is a

ligHt Heat andfrom ZerLux FINDING THE SOURCE

Page xx

Page 6

Page 30

Bringing you the latest innovations

in exploration, production

and refining September 2014

Issue 27

SURF’S UP Clariant Oil Services’ SURFTREAT® flowback aids Page 10

Clariant Oil Services’ philosophy

ALL IN THE CHEMISTRY

The Royal Society of Chemistry talks oilfield innovations Page 4

EXTENDING LIMITS

Viscodrill™ from OMNOVA Oil & Gas Page 8

IN THE PIPELINE pipeline

Shared idealS

Our Q&A tackles efficiency and inspection

and Enhancing collaboration communication with nuVa

Page 12

Page xx

JOINT VENTURE system

Careful abandon low

Radyne’s Merlin speeds up field joint coating

Tom Leeson discusses prices and decommissioning

Page 17

OTC HEREto OTC’s

A look ahead latest innovation event Page 22

Page xx

ITH T W EN W TMe 34 NOCRUIpag RE see

a bit different non-contact

Is GA Drilling’s P&A? PLASMABIT the future of Page xx

38

May 2015

Japanese shipbuilders to LNG see a renaissance thanks

Pages 13 to 27

How EOR is helping

Divine intervention

and refining

Cutting-edge CArriers are poised to

An in-depth look integrity and technology

Life Longer sheLf Statoil reach 60% recovery

36

Issue 33

June 2015

F Future-proo at asset

Issue 36

TOP TECHNOLOGY FROM TELEDYNE

in exploration, production

Issue 34

July 2015

Issue 35

August 2015

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Embracing the potential of 3-D printing

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in exploration, production

AkzoNobel’s

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Bringing you the latest innovations

supply sustainable chemical oilfield take on the future of the

Pages 11-25

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Page 6

Our supplement tackles production efficiency innovations

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Page 12

Utility ROV Services’

CLEAN AND EFFICIENT

LS NAIDE TIOT INS ENLEMEN-27 NVSUPP s 11 COCIAL ge UN SPE Pa

RETURN OF REFRACK

IC IDE EISM INS /S ENT NGPPLEMs 9-23 ILLICIAL SU ge DR SPE Pa

Page 18

Down tools unique subsea equipment

Page 8

Page 9

Prof. Maarten how deep learning could revolutionise seismology

5

ASK THE EXPERTS Subsea Q&A Page 8

SUIT UP

TRACING TO WIN

Tracerco’s tagging technology Page 12

Heated diving equipment from entro

The power and the Glori

Page 18

NEW YEAR, NEW CHALLENGES Neil Gordon

2015 Annual Subsea UK’s surveys the field Page 4

Glori Energy’s microbial EOR technology

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The World’s Largest Subsea Exhibition and Conference Aberdeen AECC 03-05 Feb 2016

WHAT TO DO IN A B E RD E E N see page 27

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Annual 2015

InnovOil

page 5

A note from the Editor OSCAR WILDE once remarked that “Nothing succeeds like excess.” It is with that view that OPEC charts the course of crude production for 2016, as we likely head into a year of even greater glut. With currencies slumping, capex being cut and hedges beginning to wilt, the outlook for the coming year is, for many, not a happy one.

It is inevitable that we tie market sentiment to technical innovation, but it is not the case in reality.

Innovation and idea generation spring from the desire to do things better, more efficiently and more effectively. An adequate rebuttal to the reductive, economic account of invention is given by Steve Jobs: “Innovation has nothing to do with how many R&D dollars you have… It’s not about money. It’s about the people you have, how you’re led, and how much you get it.”

One fitting theme for this year might be the observation that the more things change, the more they stay the same. Producers have scrambled to slash costs, work smarter and collaborate better – perhaps the only difference in a depressed market is the increased pressure for them to do so.

Neither have we seen any shortage of new and innovative ideas this year. Our “Best of 2015” section covers ten of the most interesting technologies and features investigated this year, covering everything from wind-powered water injection to microwave-powered oil sands extraction.

Even in difficult times, the industry adapts and throws its support behind ideas with the potential to improve, streamline and disrupt.

In 2016, this is likely to be more important

than ever. With a global deal reached at the COP21 summit in Paris, pressure will mount on the energy industry especially to reduce its emissions and to work more efficiently.

In this, our 2015 Annual, the NewsBase editorial team also look back on the year’s most interesting developments, and ahead to the trends and projects to watch in 2016. Even as the North Sea declines, the issues of decommissioning will push new expertise and techniques into the sector. Fresh opportunities also abound in Latin America, where a new government in Argentina could signal another unconventionals boom.

We also discuss Lloyd’s Register Energy’s latest Oil and Gas Technology Radar report, fittingly titled “Innovating in a New Environment.” The group’s survey of over 450 industry personnel offers insight into how the industry is keeping up with its innovation goals, where improvements can be made, and most crucially, how firms can continue to innovate despite low prices. In particular, greater collaboration and technology transfer from other sectors will play an important role.

For now though, we’d like to thank all the inventors and innovators featured this year for their help and courtesy in discussing their technology with us. We will return soon in the New Year with our Subsea Special, as well as our usual stable of events, interviews and features to keep you informed of the latest technology and innovation news.

All that remains is for me and the InnovOil team to wish all our readers a pleasant festive season, and all the very best for a prosperous 2016.

Andrew Dykes Editor

NEWSBASE

page 6

InnovOil

Annual 2015

First oil from Edvard Grieg Lundin achieves first oil from its new key infrastructure in Norway’s Utisira High

S

WEDEN-BASED Lundin Petroleum achieved first oil at its flagship Edvard Grieg project on November 28, giving the company’s production levels and cash flow a significant boost. Lundin CEO Alex Schneiter said the project had delivered first oil “on schedule and on budget.”

Edvard Grieg is located in Production Licence (PL) 338, on Utsira High in the Norwegian North Sea. Lundin holds a 50% operative interest in PL 338, with partners OMV (20%), Statoil (15%) and Wintershall (15%).

Edvard Grieg was discovered in 2007, and is currently estimated to hold 187 million barrels of oil equivalent in gross 2P reserves. The project’s developers anticipate peak production of 90,000 barrels per day of oil plus 1.5 million cubic metres of gas.

Lundin also intends to use Edvard Grieg as a field centre, utilising its facilities to receive oil and gas from neighbouring Det Norske-operated Ivar Aasen for further processing.

Partner Statoil was responsible for building the export pipelines, which will

transport oil to the Sture terminal on Norway’s west coast, while exporting gas separately to a facility in St Fergus, Scotland, UK. A successful appraisal well on the southeast part the field was completed in August, and is projected to increase estimated reserves once Lundin completes the certification process for 2015.

SpareBank 1 analyst Knut Henrik Rolland told NewsBase: “Edvard Grieg is Lundin’s flagship, and it was very important that they managed to bring it on stream before year-end within budget.”

He added: “Incremental barrels over the Edvard Grieg platform will have high value owing to reduced capital investment requirement and low operating costs.”

Arctic Securities analyst Henrik Madsen said his institution expected Lundin’s appraisal work to increase Edvard Grieg’s reserves by 20-30 million boe.

Luno green light Meanwhile, Lundin last week received drilling approval from the Norwegian Petroleum Directorate (NPD) for wildcat NEWSBASE

well 16/4-10, which is located southwest of its Luno II discovery in Production Licence (PL) 544. Luno II is one satellite prospect that could be tied back to Edvard Grieg in the future.

Madsen said that while the importance of getting Grieg on stream could not be overstated, the project remained Lundin’s key risk into next year. “Grieg volumes will be absolutely vital to generate enough cash flow to cover the quite substantial capex requirements going forward on Johan Sverdrup,” Madsen said. “On our estimates, Lundin will invest US$3.3 billion in Johan Sverdrup from 2016 through 2019.”

He highlighted Lundin’s current liquidity position of around US$670 million, with a potential US$1-1.5 billion available if the firm expands its current debt facility.

“We will need to see stable and increasing production towards plateau levels through 2016 to feel the geology [at Edvard Grieg] has been understood and that the topside is working as expected,” he said. n

Annual 2015

InnovOil

GAIL uses space technology to monitor pipelines

page 7

With pipeline monitoring now being done by drones and sensors, GAIL (India) is looking at satellite technology

I

NDIA’S state-run GAIL will soon launch a satellite surveillance system for monitoring its 13,000-km gas pipeline network. The company wants to enhance security on its transportation system.

GAIL will co-operate with India’s National Remote Sensing Centre (NRSC), a subsidiary of Indian Space Research Organisation (ISRO), to implement a new surveillance system called Bhuvan-GAIL portal. The system will use space technology to survey GAIL’s pipeline network, which the firm said would be an effective way to monitor the pipelines’ Right of Use (RoU) management. This is currently carried out by monthly helicopter surveys.

“GAIL will start live satellite monitoring of the pipeline RoU by January 2016 and is also looking for alternative methods like advanced Unmanned Aerial Vehicles (UAV), which can also be integrated with this system,” the firm said.

The portal operates with manual and autochange analysis to track changes along the RoU. It is employable within the RoU as well as up to 1 km outside the system.

Aboveground pipelines are usually monitored by fixed-wing airplanes and helicopters because they have the manoeuvrability to follow the course of pipeline corridors while capturing high-resolution imagery at low altitude.

However, satellite sensing technology has emerged as a viable alternative in recent years as new high-resolution satellites and object-oriented image analysis have become available.

GAIL says it has developed an application that can instantly upload pictures from mobile phones to the portal, which it hopes will quickly establish what is occurring on the ground. Data will then be sent via a report system to be integrated

with the Bhuvan-GAIL portal. This will then notify “relevant executives” of GAIL via SMS of any changes noted along the RoU, as well as newly available satellite imagery.

In June 2014, unnoticed corrosion in GAIL’s pipeline in Andhra Pradesh caused a gas leakage and a fire in East Godavari, near to a refinery operated by ONGC. The incident claimed at least 18 lives and underlined the need for enhanced monitoring systems on pipelines in India.

GAIL has studied the technical feasibility of utilising space technology with imagery from Indian satellites before moving to higher resolution foreign satellites. The company’s pilot project was performed on a 610-km pipeline that runs from Dahej to Vijaipur.

Scratching the surface Satellite imaging and monitoring as a service for oil and gas has grown in recent years, driven by the proliferation in available satellites, and the cost and resolution of the images and information available. The latest commercial satellites now have a ground

A DigitalGlobe/Exploration Mapping image using SWIR in Cuprite, Nevada, US. NEWSBASE

sampling distance of up to 30 cm, meaning they can be used to detect vital details and asset information before physical site inspections.

Service companies such as Fugro, DigitalGlobe and SkyWave provide a number of services from mapping to infrastructure monitoring via linked SCADA systems. Using different spectral bands also allows firms to see different surface information – using the shortwave infrared (SWIR) part of the spectrum even enables researchers to study rock properties.

Indeed, a recent agreement between DigitalGlobe and Exploration Mapping Group will see the two co-operate, using the former’s WorldView-3 satellite to map geology and minerals key to petroleum discovery. Again, SWIR and near infrared (VNIR) bands will be used to analyse host rocks where oil deposits are located.

With competition in the sector already heating up, the growing prevalence of such technology means that in the coming years it is likely that more and more exploration and asset monitoring will be aided – or even carried out – by satellites. n

page 8

InnovOil

Just a phase?

Researchers at North Carolina State University have created a new form of solid carbon – and it is harder than diamond

D

ESPITE being the fourth most abundant material in the universe, we know comparatively little about carbon. It may therefore come as no surprise that researchers at North Carolina State University have discovered a third phase of solid carbon – distinct from the other known phases of graphite and diamond.

Dubbed Q-carbon, the elemental phase is a diamond-like structure at room temperature and pressure. At the same time, it is also harder than diamond and will glow when exposed to even low levels of energy More intriguingly, it is also roomtemperature ferromagnetic (RTFM) – a property unique to the phase. As lead author of the research, NC State’s John C. Fan Distinguished Chair Professor of Materials Science and Engineering, Jay Narayan, notes: “We didn’t even think that was possible.”

Although the phase is unlikely to occur naturally, Narayan suggests it could be found inside the core of some planets.

The relative ease and inexpensive methods by which the material can be produced means the team has already identified some interesting applications.

“Q-carbon’s strength and low workfunction – its willingness to release electrons – make it very promising for developing new electronic display technologies,” Narayan suggests.

How it’s made According to the team’s paper, published in the Journal of Applied Physics, Q-carbon is formed as result of quenching from the super-undercooled state by

Annual 2015

Atomic structure of a graphene film

using high-power nanosecond laser pulses. Amorphous carbon – elemental carbon which does not have the crystalline structure of diamond or graphite – is applied to a glass, sapphire or polymer substrate before being hit with a single laser pulse for around 200 nanoseconds.

This pulses raises the temperature of the carbon to 4,000 K (3,727°C) before it is rapidly cooled, leaving a film of Q-carbon, which can be controlled depending on the desired thickness. The paper suggests a current range of between 20-500 nanometres depending on the process.

Changing variables in the process also leads to different results. By using different substrates and pulse lengths to control the rate of cooling, Narayan and his team can create a range of singlecrystal diamond objects.

Not only that, but it can be done “without need for any catalysts and hydrogen to stabilise sp3 [hybridisation] bonding for diamond formation,” and, of course, at room temperature. “We’re basically using a laser like the ones used for laser eye surgery,” Narayan says, “So not only does this allow us to develop new applications, but the process itself is relatively inexpensive.”

The single-crystalline structure of these materials makes them “stronger than polycrystalline materials,” he adds.

While full applications have not yet been perfected, Narayan draws attention to the potential for “diamond nanoneedles or microneedles, nanodots, or large-area diamond films, with applications for NEWSBASE

Scanning electron microscopy image of microdiamonds made using the new technique. drug delivery, industrial processes and for creating high-temperature switches and power electronics.”

“We can make Q-carbon film, and we’re learning its properties, but we are still in the early stages of understanding how to manipulate it,” Narayan says. “We know a lot about diamond, so we can make diamond nanodots. We don’t yet know how to make Q-carbon nanodots or microneedles. That’s something we’re working on.”

The university has filed two provisional patents filed on the material and the techniques for diamond creation. n

Annual 2015

InnovOil

Drones and the energy sector: SkyTech’s the limit

page 9

Joshua Potts of SkyTech examines how drones are shaping the future energy landscape

T

HE energy industry is a smorgasbord of competing theories on how best to manage resources. Yet what is currently uniting companies is the desire to sharpen maintenance tools to save time, money and avoid uncertainty about the viability of existing and developing infrastructures.

Drones are incredibly useful for the energy sector. A wind turbine, for example, must undergo rigorous inspection for dents or holes in its blades, something that has always carried a commitment to manual solutions. Normally, relying on foot patrols and helicopter flights means that a significant portion of turbines do not last their full 20-year lifespan, simply because these operations are slow to enact on a large scale. Drones – or unmanned aerial vehicles (UAVs) – by contrast, can get close to inaccessible infrastructure quicker and more safely than rope-access workers.

They are also more environmentally friendly – one doesn’t need several hundred litres of aviation fuel for a 15- minute ROAV flight.

Although drones account for 2% of all wind farm surveys, demand will grow exponentially when the hundreds of thousands of turbines that currently exist reach the end of their warranty period.

Since the commercial UAV sector is already on track to eclipse its military rival by the end of the decade, speculation has already begun on how long it will be before current legislation catches up with market trends.

The oil and gas sector was one of the first areas that welcomed drones with open arms, and is leading their wide-scale application.

Engie has been deploying models for nine years to survey hundreds of miles of pipeline. BP is using them to inspect flare stacks and onshore oil sites: for example, staying on top of tricky weather conditions

in Alaska’s Prudhoe Bay. Even for smaller-scale inspections, such as monitoring a single cooling tower, UAVs negate the need for scaffolding rigs and spot-checks that can last a day or more.

BP’s technology director, Curtis Smith, was evangelical when discussing pipeline inspections in 2014 with The Wall Street Journal, enthusiastically citing engineers who gathered “more data in 45 minutes than we’ve gotten in 30 years”.

The efficiency of UAVs is certainly set to encourage the spread of the technology across the energy sector. Greater savings on inspection costs means energy sources NEWSBASE

are cheaper and easier to maintain, keeping the price of energy down for the rest of us. As remote – and even autonomous – technology grows in usage and capability, it may even allow the energy industry to push further into challenging environments.

In this same revolutionary spirit, SkyTech 2016 will showcase the latest developments in UAVs for the energy industry on the 27-28th January, 2016 at London’s Business Design Centre. Featuring an exhibition, 3 conferences with a range of industry speakers, as well as workshops, product launches and live demonstrations, SkyTech is the ideal destination for those looking to stay informed about the UAV industry. n Contact: Robyn Doyle, Marketing and

Communications, Charles Maxwell Tel: +44 (0)151 230 2107 Email: robyn.doyle@charlesmaxwell.co.uk Web: www.skytechevent.com

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InnovOil

Annual 2015

2016: Global outlook

The NewsBase editorial team looks back on 2015 and charts predictions, projects and innovations on the horizon for the coming year

Africa African exploration continued to lead the world in 2015, although the discoveries were largely driven by deepwater gas volumes, which may prove hard to monetise. The richness of this resource is driving continued interest in floating LNG (FLNG). This technology remains unproven but Gazprom’s decision to support Perenco’s work offshore Cameroon, signing up to an offtake agreement, suggests it is gaining traction.

Italy’s Eni, in particular, had a strong year, particularly in the shallow-water

pre-salt areas off West Africa, where it was able to focus on near-field opportunities.

The largest find of the year – Eni’s wholly owned Zohr offshore Egypt – has reinvigorated interest in the Eastern Mediterranean region. However, given the fact that before drilling Zohr had been thought to hold liquids demonstrates that surveying work still has some way to go.

Disappointments continued in Kenya, outside the South Lokichar Basin, suggesting Tullow Oil and its partners have

not yet cracked the code for the East African rift system. Given the conservative mood of the industry at large, a major theme has been cost reduction, particularly with regard to deepwater. This has been reflected in other ways. Total, for one, has made move to a more flexible service staff at its floating production, storage and offload (FPSO) vessels offshore West Africa – a decision which has gained some interest – although safety remains paramount.

Ed Reed, AfrOil Editor

The Uthmaniya pilot CO2 injection project was launched at Ghawar in July, and Aramco hopes that tertiary recovery techniques could raise recovery rates from the field as high as 70%. The pilot scheme will continue through to the end of 2016 before the company determines whether a wider roll-out is commercially viable.

Also, Wintershall signed an agreement with Abu Dhabi National Oil Co. (ADNOC) in early November to co-operate on research and development (R&D) for chemical enhanced oil recovery (cEOR) technologies tailored to

raise recovery rates at the emirate’s fields.

The state-owned oil firm has experimented with various advanced recovery techniques at its maturing and most-complex fields and has followed an industry trend in signing up international oil company (IOC) partners to assist in developing bespoke solutions.

Chemical injection is the least used across the world of the three main EOR techniques but has been gaining ground, with Oman the regional pioneer and a pilot project under way in Abu Dhabi outside ADNOC’s purview.

Ian Simm, MEOG Editor

Middle East In the still buoyant Middle East, EOR was one of the key themes of 2015 – a note that will continue to sound throughout next year.

In Oman, having successfully tested a solar steam injection enhanced oil recovery (EOR) pilot project, Glasspoint and Petroleum Development Oman (PDO) have begun construction on the Miraah project at the Amal oilfield.

Of all the Middle Eastern hydrocarbons producers, Oman has repeatedly shown itself to be at the forefront of adapting to the enduringly low oil price environment in an innovative and speedy fashion. This is unsurprising given its 2015 budget breakeven price of US$110 per barrel of Brent and the energy sector accounting for around 80% of its total revenues.

Oman’s oil is amongst the most difficult in the world to extract from its deep carbonate reservoirs, resulting in up to US$20 per barrel in enhanced oil recovery (EOR) costs added to the US$15 per barrel or so of standard operating cost (including capex). It puts it behind regional rivals, such neighbouring UAE’s US$7 per barrel.

In late 2015, Saudi Arabian officials also presented Saudi Aramco’s maiden tertiary recovery project at Ghawar – the world’s largest oilfield – to an environmental forum, revealing their major ambitions for the potential of such technologies to ramp up recovery rates and thereby cement the kingdom’s market dominance well into the future.

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Annual 2015

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North America The main driving force in North America continues to be shale development, and that unconventional drillers are still showing remarkable resilience in the face of low prices. However, as efficiency gains in shale plays can be attributed in part to services firms being forced to reduce their prices, such gains may slow over the coming year.

Borrowing base redeterminations will be another factor to watch next year, after banks proved surprisingly lenient during the last round of redeterminations.

Other trends that emerged included a backlog of drilled but uncompleted shale wells that can be brought on line at a later date, when they can be more profitable.

Others have turned to refracturing existing wells in an effort to produce more oil more cheaply. Development of refracking is still at an early stage, and

the technique could yet be employed more in the future, when they have learned how to target it more effectively. EOR techniques are also being trialled in shale plays as drillers experiment with a variety of methods in order to produce more at a lower cost.

Shale wells can be brought on line comparatively quickly and easily. But other types of projects are also under development and due to come on line in the next year, particularly in the deepwater US Gulf of Mexico. In 2016, notable projects starting up in the Gulf include Royal Dutch Shell’s Stones, ExxonMobil’s Julia and Anadarko’s Heidelberg spar.

Other notable developments to watch include the start-up of LNG exports from the US, with Cheniere Energy’s Sabine Pass terminal expected to ship its first cargo early next year.

NEWSBASE

Meanwhile, US politicians continue to fight over proposals to end the country’s crude export ban. However, dealing with issues such as this may be put on hold until after the upcoming presidential election in 2016, another major deciding factor for future oil and gas industry policy.

A number of new phases for oil sands projects in Canada are also set to come on stream, though other oil sands schemes have been scrapped for now. Alberta – home to the oil sands – is also going to come under increasing pressure to tackle carbon emissions under its new government. More broadly, Canada’s new federal government will also shape the country’s energy development, including major pipeline projects and exports.

Anna Kachkova, NorthAmOil Editor

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Annual 2015

Latin America As with all regions in the world, 2016 looks like it will be a mixed bag for Latin America. The oil price crash has inevitably had an impact on investment in exploration and production, primarily in Brazil’s expensive deepwater pre-salt projects. Yet there remains low-hanging fruit elsewhere which could prove irresistible to investors, notably in Argentina and Mexico, where high-spec technology will be fundamental to harnessing considerable untapped reserves.

Argentina could become a hive of investment with the election of rightleaning Mauricio Macri as president in November. His government is likely to be far more pro-investment than the outgoing Fernandez de Kirchner administration, which stymied energy capex with its skewed populist policies. Macri has already appointed former Shell Argentina CEO Juan Jose Aranguren as his Energy Minister, a positive signal to the industry that things will be different. Argentina needs lots of

Mexico is the other big investment story in the region. The country is to hold its first ever deepwater auction in early 2016, which is likely to attract the interest of global majors. The deepwater acreage on offer will be mere miles away from projects in the Perdido Fold Belt in the US Gulf of Mexico that are already being developed by companies like Shell.

It is not fanciful to anticipate that companies active on the US side of the maritime border will be looking for assets on the Mexican side and will take their deepwater technology expertise with them – if they win blocks. A spike in spending offshore Mexico offers some hope to the beleaguered global services industry.

Offshore Brazil is a different story. The oil price collapse has compounded an unprecedented political crisis at staterun Petrobras. The company has been abused by the ruling Workers Party for years, with corruption and malpractice causing chaos in the services sector.

Many contractors have been banned from bidding for new business while legal investigations are under way.

Brazil’s punitive local content rules and recent industrial action add more risk and make the country a poor investment choice for many IOCs, despite the obvious wealth of resources it possesses. The paltry turnout in Brazil’s latest oil bid round indicates the poor state of the industry and suggests it is unlikely to be a hotbed of innovation and technology ramp-up in the next 12 months and beyond.

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cash and new technology to develop its hydrocarbon resources, especially in its largely untapped shale plays such as the Vaca Muerta.

Expect to see more oilfield services companies turning their attention to the country if things remain tight in US unconventionals. The emergence of a dynamic technology industry in Argentina is also likely, as local companies look to launch their innovations into the expanding shale sector.

Annual 2015

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Europe Elsewhere across Latin America the price crash has wreaked havoc on hydrocarbondependent economies. Venezuela has gone from bad to worse with an economic crisis that has made the country a basket case. There is zero hope for any innovation advances, as state-run PDVSA is routinely raided by the government to fund its social programmes. One day Venezuela will become a source of considerable technological advancement, as the country needs complex upgraders to prepare its extra heavy crude for refining. But with the incompetent PSUV still in power and the promise of political chaos for years to come, that day looks to be some way off.

Ecuador has also endured a tough year on the back of low prices. But the country does have the Ishpingo Tambococha Tiputini (ITT) project as a possible beacon of hope for the future. The construction of the first platform at the ITT oilfields has been completed, with drilling work at the Tiputini field due to begin in January. Investment in this field alone is projected to top US$1.8 billion, with output from all three fields forecast at around 225,000 barrels per day by the end of the decade. Ecuador relies on investment by foreign services companies to extract its oil, so there will be considerable opportunities for technology developers as state-run Petroamazonas seeks partners to develop its resources.

Finally, Bolivia is stepping up exploration to ensure it does not run out of natural gas, the lifeblood of its economy. France’s Total and UK-based BG Group have already pledged to invest over US$1 billion in oil and gas exploration in the Andean country over the next three years.

It is also poised to launch a three-year oil and gas exploration survey in the coming few months as part of efforts to increase hydrocarbon supplies to domestic and foreign buyers. State-run YPFB has put out a call for companies to bid for the geological survey work, which will be split into nine zones. It is an attractive opportunity for innovative seismic companies to step in and make some money in a region that is braced for another tough 12 months.

Ryan Stevenson, LatAmOil Editor

The North Sea is one of the highest cost operating areas in the world. The drop in oil prices has had a cruel impact on the region, leading to thousands of job losses and costcutting by operators across the board. This trend has been replicated on both sides of the sea, with the UK and Norwegian parts feeling the pain in equal measures.

That said, there are still investment opportunities. Private equity houses are stalking stakes in distressed assets and companies to take advantage of the downturn. One example of this is Russian billionaire Mikhail Friedman’s LetterOne vehicle, which has divested out of the UK North Sea but has begun to build a significant footprint on the Norwegian side.

The influx of new money into old assets will require the adoption of innovative technology to maintain output or at least delay declines. While the price crisis has had an impact on exploration and production investment, opportunities remain for technology developers to cash in, especially those with expertise and aimed at asset integrity, inspection, monitoring and maintenance. Indeed, innovation is even more important now as companies look to do more with less cash and human resources.

Price has also had an effect on the decommissioning pipeline in the North Sea. With many projects becoming too expensive to develop, some operators are opting to take them out of commission early. This presents opportunities to companies that specialise in taking equipment apart rather than building it.

That is not to say that major projects are not coming on stream. The Edvard Grieg project in the Norwegian North Sea produced its first oil at the end of November. Norway’s Johan Sverdrup project, meanwhile, has been

NEWSBASE

a rare shaft of sunlight in the gloom for the European services industry, with companies competing hard to win contracts, much to operator Statoil’s delight, as it has driven down the project’s costs considerably.

New contract awards are likely to continue throughout 2016.

The UK does not have any Sverdrupsize projects on the horizon, and Chancellor George Osborne drew the industry’s opprobrium in his recent Spending Review when he failed to offer any new incentives (like tax cuts) to the North Sea. The British Government appears satisfied it has done enough to help the industry and is now focused on expediting onshore E&P. This will largely be driven by onshore unconventionals, with the government recently taking action to overrule local authority blocks on shale gas development to ensure that more speedy progress is made.

Elsewhere in Europe the E&P sector is largely moribund. There have been a few successes such as gas finds in the Black Sea, but things largely remain downbeat. Perhaps the only other area worth watching is the Eastern Mediterranean, where gas continues to be found, raising hopes that a dynamic gas hub could emerge.

Eni’s discovery of the Zohr gas field offshore Egypt has also reinvigorated exploration plans, with Total saying it will begin work off Cyprus again in 2016. This offers opportunities to seismic companies and also LNG investors, as the region’s participants ponder how best to monetise their gas.

Overall, next year looks likely to be another hard one for Europe’s upstream, with better things anticipated in 2017 and beyond.

Ryan Stevenson, EurOil Editor

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Annual 2015

Russia Despite the political rhetoric, the impact of international sanctions which bar Russian producers from accessing sophisticated Western oil and gas technology is beginning to become visible. While output has not been affected yet, a number of companies have scaled back plans on challenging projects.

Russia’s attempts to develop Arctic reserves and tight oil have become in most cases either unfeasible or impossible owing to a lack of adequate technology, and a price which does not support such investment. Several international firms have already announced plans to exit these areas because of sanctions. They will also have an

impact offshore oil and gas production and efforts to arrest declining output from the West Siberian brownfields.

Moscow claims it can source technology and equipment from China and Asia while developing its own technological ability. Yet the standard of technology in China is not on par with that of the West and Japan.

In response, state-controlled RosTech has pressed ahead with forming the Unified Heavy Machinery Corp. (OMK) with partners Rosneft, Rusal and other major domestic firms. RosGeologia, the state-controlled geological research operator, has formed a similar venture with state-run Rosatom with

NEWSBASE

a view to creating new geological exploration and survey equipment and software.

A prolonged slump in oil prices and subsequent sharp economic downturn makes it difficult for producers and manufacturers to invest in new technologies and high-cost projects. Making matters worse, sanctions have restricted the ability of some oil companies to raise capital on international markets. The government has also recently introduced higher taxes into next year as it tries to shore up the national budget, again limiting the capital available for R&D. Joe Murphy, FSU Editor

Annual 2015

InnovOil

Asia

LNG

Asian refiners are scrambling to improve efficiency, with residue upgrading technologies of increasing importance to plant operators.

While lower oil prices have helped refineries post stronger margins in recent months, regional competition remains strong. As such, conquering the bottom of the barrel remains core to ensuring a competitive edge.

Sumitomo Chemical said this month that it had agreed to license its polypropylene (PP) and propylene oxide (PO) manufacturing technologies to South Korea’s S-Oil. In September, S-Oil reached a final investment decision (FID) on a residue fluid catalytic cracking (RFCC) plant at its 669,000 bpd Ulsan refinery. Once complete the unit will allow the company to produce high-value gasoline and propylene from the residue oil. S-Oil plans to use Sumitomo’s technologies to convert the propylene into downstream products.

Exploiting residue oil is also gaining importance in China, where a recent Honeywell UOP-commissioned survey of state and independent refinery operators revealed that local players were chasing “breakthrough technologies” in extracting more value from every barrel of crude.

Asia’s exploding downstream capacity has highlighted the need for operators to become more efficient and improve refining margins however possible.

Regional crude distillation unit (CDU) capacity has been forecast to grow by around a third from almost 30 million bpd in 2010 to more than 40 million bpd by 2020.

This will force less efficient refineries to make way for more advanced facilities.

This can already be seen in Australia, where older, smaller plants have been unable to vie for local market share with Asia’s biggest facilities.

Japanese refiners have also been forced to rationalise capacity in a bid to survive. JX Holdings and TonenGeneral Sekiyu announced merger plans this month following a similar statement from Idemitsu Kosan and Showa Shell Sekiyu in November.

Even as refiners work to scrape the bottom of the barrel, new capacity planned for China, India, Indonesia, Malaysia and Vietnam will likely force further closures of older plant.

In the upstream, meanwhile, work continues apace to unlock Australia’s shale gas potential.

Ireland’s Falcon Oil & Gas has said it will drill two wells on its 4.6 million-acre (18,600-square km) shale venture in Australia’s Beetaloo Basin in the first half of next year. The wells will then be hydraulically fractured and, if successful, the wells’ gas flow rates will be tested in the third quarter.

The licence area could hold as much as 160 trillion cubic feet (4.53 trillion cubic metres) of gas, compared with an estimated resource potential for Australia of 396 tcf (11.21 tcm). Given that Australian major Santos said in late 2014 that the country still had another 5-10 years left before it would begin to produce the fuel at viable quantities, progress in the Beetaloo will be of particular interest in 2016.

Andrew Kemp, AsianOil Editor

The LNG industry entered a perfect storm in 2015, with prices under continued pressure. This has largely been the result of slowing demand and the continued link to oil prices, leading to a gloomy outlook even while major projects started up, the most significant being in Australia.

The sector remains slow moving, while spot prices are not, leading to a major dislocation and threatening projects that have not yet reached FID. While Japanese demand fell in 2015, and with more nuclear power plants (NPPs) likely to come back on line this trend is likely to continue.

However, smaller-scale and marginal importers, taking advantage of more flexible options – in particular floating storage and regasification units (FSRUs) – did provide some support for additional output coming to the market.

Egypt, for instance, has lined up two FSRUs and is in talks to take on a third for 2016, while Pakistan began imports half way through the year.

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Floating infrastructure provides a number of opportunities when compared with traditional landbased plants, particularly in the speed at which projects can be deployed – and potentially moved – even if capacity upgrades are constricted by a lack of space.

The deal reached at the COP21 talks in Paris in early December signals a key change in global energy policy, but one factor which may be overlooked is the support it may offer for the use of LNG as a transport fuel. Shifting to this feedstock would provide substantial reductions in NOX and SOX emissions. As a result, it is finding increasing favour as a marine fuel in North America and Europe, while China may also be eager to push LNG as a solution to its increasingly broadly known problems with smog. This may help to shore up some extra demand in the next few years, as well as offering shipbuilders, engine manufacturers and other maritime innovators further opportunities to distinguish themselves.

Ed Reed, Global LNG Editor

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On the Radar

InnovOil

Annual 2015

We sat down with Lloyd’s Register Energy to discuss its most recent Oil and Gas Technology Radar report, tackling how the energy industry is “Innovating in a New Environment”

O

NE of the greatest challenges for firms this year has been supporting new innovation with investment. As has been seen across the board, low prices have meant slashing the latter, with spending on new technology or long-horizon research and development often one of the first targets.

The industry’s shift in priorities since September 2014 means that the tone of Lloyd’s Register Energy’s (LRE) 2015 Oil and Gas Technology Radar report has taken a markedly different tone to its predecessor. Working with Longitude Research, Lloyd’s Register surveyed and interviewed over 450 industry professionals for their take on the market.

Where last year’s report took a wideranging view on short- and long-term technology trends, this year’s is on the specific and timely subject of “Innovating in a New Environment.” Indeed, even in the high times of last summer, the authors conceded that investment in future technologies “will be unpredictable and complex, and will always be, to a degree, conditional on expected future oil prices,” – a message which now seems eerily prescient.

The resulting 2015 data offer some sound insight into the challenges the sector is facing, the attitudes of those involved and – more promisingly – where the industry may look to source solutions for its most pressing concerns.

Less money, more problems Tellingly, 76% of survey respondents believe that unstable oil prices have led their firms to slow or halt new innovation projects.

This has been seen in the delay of deepwater projects, the cancellation of some work in frontier areas – the Arctic is no longer the new prize it was a year ago – and staff cuts within almost every business department.

Last year, 68% of the survey’s respondents intended to increase their R&D budgets in the next 2 years. Such optimism seems unlikely to be matched in 2015 and 2016.

Accordingly, innovation is still needed, but to tackle an enormously different outlook. This “refocusing of the lens,” as Lloyd’s puts it, actually means that some work may be accelerated. Projects which were close to completion may be allocated extra resources in order to speed up deployment or guarantee their ROI. Society of Petroleum Engineers president Nathan Meehan commented that these fast-tracked priorities “may be in material science or efficiency improvements, or displacement of other technologies. However, long-term, NEWSBASE

disruptive innovation projects are going to take a back seat for now.”

Financial incentive, as always, is the primary driver. For BP’s group head of technology, David Eyton, that means a priority on better water-flood enhanced oil recovery (EOR), a technique which is not as adversely affected by lower prices as some of its rivals (e.g. thermal EOR or polymer injection). Given it is also the most widely used form of EOR, the scalability of this in a global organisation like BP makes similar sense.

Standardisation, a topic which has floated around the subsea industry in particular for years, is also on the innovation agenda. Lloyd’s cites an anonymous respondent who believes that subsea trees are moving closer towards full electrification (rather than the current electro-hydraulic models), and is developing a model which allows these parts to be swapped in as replacements at a later date. Expanding this concept across the whole sector will require a great deal more innovation in standardised design.

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Annual 2015

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Innovation priorities in a low-price environment

67% of oil and gas executives believe that the oil price will stay between $50 and $70 a barrel in the next year.

How will this oil price impact their innovation priorities?

0 Now, the primary drivers of innovation investment are:

76% Say oil price instability has led them to slow down or halt most innovation initiatives

46%

Improving operational efficiency

36% Reducing costs

35% Deployment of new technologies remains a major innovation challenge:

70% say the challenges involved with the real-world deployment of new technologies is a key barrier to innovation

Improving access to potential reserves

56% say data collection and analytics will be important to their innovation efforts over the next two years

Most of what we're embracing in data capabilities are coming from outside,

developed for other industries. There are described fantastic companies and universities Collaboration consternation their firms as “selective” who have data analytics that are opening our eyes to what might be possible.

Standards also highlight the double-edged collaborators, while only 16% were David Eyton, Group Head of Technology, BP sword of collaboration: equipment can “enthusiastic.” While majors and often be more cost-effective if a template supermajors appear happy to work with or design can serve multiple purposes, or service and technology providers to form if design and assembly can be streamlined. various joint industry projects (JIPs) and Yet few firms are particularly willing to give tie-ups – Lloyd’s cites Statoil as a stand-out up business they could otherwise compete example – few upstream explorers seem for on their own, nor give up IP where it willing to collaborate with those in the can be helped. same sector.

One major finding of the 2014 report But respondents seem to think that was that firms which collaborate are more this wariness may finally change. As likely to be successful. This year, data investors exert pressure on operational suggest that more specific conclusions costs, financial results and increasingly could be put forward: “Companies that environmental impacts, many may be collaborate more actively in technology forced to become more innovative about innovation perform considerably better how they work – despite the perceived than their peers in all the different facets issues. Technip’s subsea regional of innovation. Those respondents who technology officer for Asia-Pacific, Robby describe their firms as ‘enthusiastic’ O’Sullivan, argues: “IP and competition collaborators in technology innovation are issues have obviously been addressed and considerably more successful in meeting resolved by other industries through open their innovation goals than ‘selective’, discussion, planning and appropriate ‘cautious’ or ‘reluctant’ collaborators,” the structuring, so there should be no reason report notes. the oil and gas industry cannot resolve The majority (43%) of respondents them.”

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Search and deploy 67% of respondents also said that the challenge of deploying new technologies in the real world is a major barrier to innovation, and 70% believe that the process of doing so is taking too long.

This is a problem which affects the newest innovations in particular, and despite the work of bridging bodies such as the UK’s Oil and Gas Innovation Centre (OGIC), is certainly made worse by low margins in an already conservative industry.

Some in the survey suggested that this was the result of a shift in scope for new technologies. During the boom years, companies looked to grow reserves by exploring new (expensive) horizons, and developing technologies which would be used in 5-10 years. Now with a more urgent focus on efficiency and cost-effectiveness, many have not yet adjusted. Even those who have prioritised the development of cost-reducing equipment may struggle to deploy it fast enough to produce the desired result.

Risk aversion remains a major issue. The UK Institution of Mechanical Engineers’ director of engineering, Colin Brown, responded: “This is due to the increasing complexity involved and the implications of mistakes. Previously, the high oil price and resulting profitability shielded companies somewhat from the risks. Now there’s less motivation to drive change because of the high financial risk of something going wrong.”

Against that backdrop, the old adage of “the race to be second” appears as relevant as ever. The head of the E.ON E&P UK Innovation Centre, Jonathan Carter, made similar comments, stating: “A lot of companies look to deploy new technologies only when they are proven. They don’t want to be the first, and that’s a barrier.”

Yet many other industries with similar risk profiles – aerospace being perhaps the most useful analogue for oil and gas – have successfully incorporated new technologies such as real-time monitoring and sensing equipment through the development phase, often far faster and with better results. The energy industry must follow that lead if it is to improve how it operates.

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Initiatives to explore the crossover potential of technologies from other industries have been talked about for years – but actual results still seem to be lagging, largely because there is a sense that technology invented elsewhere is unlikely to be fit for purpose in the oil and gas sector. This is a problem affecting those both inside and outside the industry, as Nathan Meehan explains: “The people who developed it were thinking outer space and it never occurred to them about high pressures or high temperatures, or needing to make it much, much bigger or in certain kinds of shapes.”

Without doubt, this is an area that is characterised by technical complexity, but one where new types of collaboration can bring about dramatic change. BP offers one example of upstream leadership in the form of its Digital Innovation Organisation (DIO), a group tasked with investigating and incorporating technology-based innovations into BP’s business units.

However, DIO looks for solutions which can have a meaningful effect within 12-18 months, meaning it is less likely to support the more speculative, long-horizon technologies.

For now at least, given the current pressures, the industry looks more likely to maintain this trend rather than adjust its horizons.

The more things change These report’s findings broadly suggest that a gloomy outlook will prevail into 2016. But it is also worth stating the more encouraging findings. In comparing the 2014 and 2015 reports, despite the market turmoil, many firms are still facing the same challenges as they were a year ago.

Last year, 44% believed that improving operational efficiency was the primary driver behind innovation, compared with a slight rise to 46% this year.

Technologies such as industrial automation and EOR led the pack last year, but remained well in the sights of those surveyed this year, given their potential to improve recovery and efficiency in the near term. Big data too remains in focus, with companies beginning to see the added benefits of harnessing such information, but as before, the uptake is not as wide-ranging as it could be.

Respondents have shown that the industry is, in fact, affected by the same problems as it always has been: difficulties in co-operation and collaboration, and a conservative attitude towards the adoption

Annual 2015

Technology

Industry

Imaging technologies for seismic modelling

ICT, microelectronics, university

Advanced lightweight and corrosion-resistant materials

Aerospace, engineering, university

Remote inspection of offshore assets

ICT

Nanotechnologies – for testing reservoirs

Biomedical, university, ICT

Data mapping – for seismic surveys ICT, university rate themselves as successful in The devil is in the Advanced data analytics – for seismic ICT,goals, university meeting their innovation deployment modelling, control systems, equipment almost as many (47%) say they’ve

identification, numerous other applications fallen short on most or all of their Meeting still ambitious objectives in

goals. This is a decidedly bleaker

a tighter cost environmentpump means technologies – Cardiovascular-type Medical self-assessment of performance oil and gasand companies ill afford for flues pipescan (flow) than that given in the previous innovation failures. It is thus a

survey, conducted in spring 2014, Additive manufacturing Engineering cause for concern that so many(3D fall printers) – shortrapid on meeting their innovation for fabrication of spare partswhen only 26% said they were goals. Upstream firms are clearly

falling short.

47%

say they've fallen short on most or all of their goals

Underwater autonomous finding it tougher to innovate vehicles; drones

Aerospace, automotive, engineering

efficiently in today’s Sensors for dataenvironment. collection – on condition of Although nearly half (48%) equipment, assets, and downhole conditions

ICT, microelectronics

Super insulation – for subsea equipment

Building materials

Carbon fibre – for deepwater umbilicals

Aerospace, automotive, university

How successful has your organisation been at meeting its innovation goals and objectives over the last two years?

35%

44%

13%

3%

Highly unsuccessful – we’ve fallen short on all of our innovation goals/objectives

Highly successful - we’ve met, or exceeded, all of our innovation goals

Register Energy Oil and Gas ofSource: newLloyd’s technologies.

While lowTechnology prices Radar 2015 survey the upstream oil and gas industry.” Doing may alter R&D budgets and short-term so is surely the only viable option in the 18 priorities, innovators still face the same short and long term. hurdles of deployment and adoption.

With low prices forcing firms to work The bright side to this – if there is cheaper, 2016 must be the year industry and one – is that there may finally be the innovators finally collaborate effectively, in impetus for more companies to change order to work smarter. n these attitudes and adapt to new ways of working. The Lloyd’s authors conclude: “A To read Lloyd’s Register’s Oil and Gas sustained period of low oil prices can help Technology Radar report, visit www.lr.org/ to erode the conservative attitudes toward en/energy/technology-and-innovation/ innovation that have long been evident in technology-and-innovation-radar/

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InnovOil

THE BEST OF 2015

Annual 2015

SPECIAL SUPPLEMENT Pages 19-44

SUBSEA SURVEYORS The vLBV and STS from Teledyne SeaBotix Page 34

TAKE IT ESEIEH

Extracting oil sands with radio frequencies Page 31

SPIN WHEN YOU’RE WINNING DNV’s wind-powered water injection project Page 20

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page 20

InnovOil

Annual 2015

THE BEST OF 2015

Wind-powered water injection could be a Win-Win In March 2015, DNV GL began the Win-Win JIP, a project aimed at driving wind-powered water injection for oil and gas. We spoke to DNV’s Johan Sandberg for a progress update

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ENEWABLE energy and the quite obvious that we wanted to go for oil and gas industry have not offshore renewables in one way or another, always made easy bedfellows. The so the third generation of wind power development path of both sectors – floating wind turbines was an obvious has often led companies and innovators to choice.” an either/or approach, despite the potential Although offshore wind was a natural benefits of closer working. choice for a company with its In early 2015, DNV GL origins in the maritime industry, launched the promisingly it does present its own challenges: titled Win-Win joint industry “Only a fraction of the world’s project (JIP), a scheme oceans are shallow enough in which sought to power water which to build offshore wind, so injection pumps with floating it was quite obvious immediately wind turbines. that we needed to focus on The operational needs of floating turbines,” he said. enhanced oil recovery (EOR), The DNV GL team wanted for example, make it a good to identify how they could make target for the application of wind power “the shale gas of renewables; many operations Johan Sandberg, renewables – a game-changer.” do not require backup power, DNV’s energy division However, to do so would require sidestepping the issue of service line leader for more than simple awareness intermittent generation, while offshore renewables of the technology, particularly the cost and life extension in an industry known for its elements often mean the initial investment conservatism. Sandberg explained: “We in infrastructure can be paid off over the quickly understood that we needed to find increased lifetime of the project. a market where this would be a purely DNV GL Energy’s Service line leader commercially driven enterprise, so we for offshore renewables advisory, Johan started to look at oil and gas.”

Sandberg, told InnovOil: “In 2013 I was given the responsibility to develop our 2050 Float on vision for renewable energy – obviously While cleaner power can reduce costs in very exciting. Given our heritage in the terms of emissions regimes (depending maritime and renewable industries it was on local environmental regulations), any NEWSBASE

solution would have to be competitive on its own merits. “We thought: why not try to see if we can identify a process where floating wind would be THE preferred solution – not because it‘s subsidised or because of the effects on emissions, but because it works and because it is cheaper than the alternative, conventional solution,” Sandberg said.

Water injection proved to be the best fit, primarily because it can often work with limited or even without backup power.

“Producers often complain that they don’t

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have enough capacity to inject water, so anything which can help add injected water could be useful,” he continued.

It is a simple idea, but not one that has been put into practice so far. While some platforms – Beatrice in the North Sea, for example – have wind turbines to generate electricity, they are supplementary to a grid connection or an independent supply.

An independent, dedicated wind system powering a specific process is a bold new step.

In particular, wind-powered injection

would be most beneficial to platforms with a lack of associated gas to drive gas turbines, or to platforms which lack sufficient generation capacity to power the process.

DNV GL’s calculations suggest a typical injection pump system requirement of around 5 MW of power, either in one 5-MW induction motor or in two 2.5-MW motors running two smaller pumps for the benefit of added redundancy. Most wind turbine manufacturers now supply 6- to 8-MW models suitable for offshore use, although few have been proved for floating NEWSBASE

applications, meaning new prototypes may well have to be considered.

It can also be cheaper, more efficient and take up less space than the alternatives.

“In some cases [operators can] retrofit gas turbines to the platform,” Sandberg explained, “But the retrofitting costs alone and the lack of production during the fitting is also a formidable cost.” For producers without enough associated gas, an installed wind system may be more economical than importing diesel or LNG fuel to power generators and turbines.

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Citing Norway’s burgeoning expertise in the wind sector – Statoil pioneered the Hywind floating wind demonstrator in 2009 and is working on a similar project in UK waters – DNV GL set to work examining the country’s 140 or so producing platforms for those which might benefit most. The early results were positive. “We saw in some cases we got fantastic results, because in many cases the alternative is just to shut down altogether and decommission your platform.”

How it works From an early stage, DNV GL considered varying designs, again dependent on the needs of different production profiles. The simplest system would see a floating turbine drive a subsea pump, injecting unprocessed seawater into the reservoir, while others of varying complexity could also be used depending on infrastructure and reservoirs.

“We looked at cases with an integrated autonomous system, where the pumping and water injection system is integrated into the foundation of the turbine, or also where the turbine is connected to the platform via cables and runs the system already installed on the platform,” Sandberg said.

Each has its merits, but an integrated floating turbine could be located far from the production host without the need for costly power cables and water flow lines, one of the most expensive considerations in a water injection system. In its initial plans, DNV GL cited Norway’s Tyrihans field, where injection water is drawn directly from the sea via a newly developed subsea unit, operated remotely from the Kristin platform, 31 km away. It is one of few cases with raw seawater injection and this kind of technology may well form the first basis of a prototype wind system.

Using raw seawater for injection is obviously the easiest method, and minimises the injection flowline, but future developments could see water processing and desalination incorporated into the system for use in low-salinity EOR operations. It is something DNV GL has considered, although it concedes that the need for significant salt removal may make a wind system unfeasible in some circumstances.

The system also offers an attractive OPEX proposition as a counterpoint to

Possible design for an internal pump system the unit’s initial CAPEX costs. “The life expectancy of these turbines is longer than the life expectancy of most injection wells,” Sandberg enthuses. “So once you’ve depleted your field, you can just take the floating turbines/injectors, disconnect the mooring, take it to another field and start injecting water there, meaning very low CAPEX next time you connect your wind turbine.”

Wind in the sails When InnovOil last spoke with Sandberg in March 2015, DNV GL was collaborating with some of the first signed participants. The final list of collaborators was released in October, with ExxonMobil, Eni Norge, Nexen Petroleum UK, Statoil, VNG, PG Flow Solutions and ORE Catapult all joining the initiative.

“Together, they cover the value chain from wind production and operation, to pump manufacturing, to five oil and gas operators,” he said.

At the time, the early sign-up of oil and gas companies was critical in order to take the project to a commercially applicable stage, through what he called “The Valley of Death” – the period where developers need a significant capital boost to take an idea to a commercial phase.

The project will now see a technical concept developed and its technical feasibility assessed in detail. Two of the main challenges being addressed are the NEWSBASE

off-grid operation of the system and the reservoir’s response to variable injection rates. Sandberg explained to InnovOil in December 2015 that success in these “depends on the level of complexity of the system.” For raw seawater injection he says that the “technical hurdles are rather few and low, but for complex oxygen removal and desalination, there are a few more processes that have to go through technology qualification.”

The system has a number of potential business models. Sandberg suggested that platform owners might take over the operation and maintenance of the turbine and pump systems themselves, or even that a dedicated business could lease or hire them out to E&P companies.

Neither is the system limited to the North and Norwegian Seas. Conditions and interest in the Gulf of Mexico are equally promising. New applications for the system are also being discussed. “Until now,” he said, “the focus has been water injection, but the results from the project are promising enough to start investigating other applications. It is a natural step to take the lessons we have learned here and look at other non- or semi-critical processes.”

The JIP has been up and running since the beginning of 2015 and is scheduled to be completed in the first quarter of 2016.

From there, DNV is working along two routes: “Technology qualification of the Win-Win system through various tests and continued development by stakeholders in the industry, and the initiation of a second JIP for investigating other applications. An invitation could be launched in Q1 or Q2, 2016.”

Most important of all, however, is the dialogue that has been generated between multiple industries. “When we meet with engineers from oil and gas, they bring so much more to the discussion than we could have come up with ourselves,” Sandberg commented. “For example, if we can drill wells differently just because we have wind turbines instead, maybe more money can be saved that way.”

In tough times especially, it is encouraging to see a progressive idea move forward with the support of industry partnerships. The speed with which DNV has gathered that support certainly suggests it is onto a winner. n

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Looking into the IRIS

The International Research Institute of Stavanger (IRIS) works with companies, universities and the Norwegian government to tackle a number of issues facing the oil and energy industry – including EOR

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VER since the first oilfields were discovered in Norway, the International Research Institute of Stavanger (IRIS) has been researching ways in which the industry can work better and work smarter. Having begun life in 1973 as Rogaland Research – a joint venture between the University of Stavanger and regional foundation Rogaland Research – IRIS evolved into its current form in 2006, having grown and changed to include work on petroleum, the environment, social sciences, biotechnology business development and the energy system in general.

Working alongside the industry – which is responsible for directing and funding a large percentage of IRIS’ research in oil and gas – it can draw from diverse expertise in offices in Bergen, Mekjarvik and Oslo, as well as its Stavanger headquarters. It is this diversity which IRIS research director of field studies and new recovery technology Roman Berenblyum believes gives the group the edge when it comes to understanding the North Sea. “We have access and expertise in both modelling and laboratory studies, and we have found over the course of the years that the ability to do both under one roof is essential” Roman says. “We’re living in a world where these two sides aren’t talking to each other often enough. It’s really important for us that the simulation guys can go back and talk to the laboratory guys and say: ‘You need to explain this a bit better because I don’t think we’re talking about the same thing.’” It is here where IRIS’ work on improved and enhanced oil recovery (IOR/EOR) comes to the fore.

“We have a lot of the EOR competencies in our group… It was very fashionable in the 80s/90s and there were many research programmes. There was a lot of EOR research work done with a lot of people, and many of them have been here for 20-30 years now,” adds research director for IRIS’ IOR Group, Ying Guo. Having been mostly shelved in the late 90s, the maturing fields of the North Sea and further afield have

led to renewed efforts to develop, test and understand better advanced methods of increased recovery.

The new “must-have” “With fields in late life,” Ying says, “EOR has become more urgent, rather than a “nice-to-have” programme for the future, because many fields will be closed down if you don’t apply a certain EOR-related project, or extend the life somehow.”

As life extension becomes a priority for operators with maturing assets – mainly from a perspective of lengthening the life of infrastructural and facilities – EOR becomes a much more pressing concern in order to maintain and increase production.

“In turn, this means operators need to gain a better understanding of their ongoing projects. For example, if you have applied water or gas injection which is common on the Norwegian Continental Shelf [NCS], then where will the remaining oil be in the late life of the fields? All of that is part of understanding EOR,” she adds.

From a research perspective, better EOR should be reinforced by this back-to-basics and multi-disciplinary approach.

This approach applies to new field development too, meaning EOR should be evaluated right from the start. Upon finding a new giant field such as Johan Sverdrup, Roman posits: “Do we do what we did thirty years ago or do we take all the knowledge we have now and build it up with IOR/EOR in mind from the beginning?”

IOR at IRIS IRIS’ IOR group has existed since the 80s and works with a wide range of IOR/ EOR methods in order to improve sweep efficiency on micro- and macroscopic levels, both in sandstone and carbonate reservoirs.

Ying explains: “We look at the pore scale of the fluid-rock system at nanometre-scale and understand how the fluid interacts with reservoir rock in the complex porous system, what happens when we put EOR chemicals or modified sea water into the system, what are the measures to mobilise NEWSBASE

the last drop out of the system, and how to describe these processes mathematically.”

Next, work is carried out at core scale.

Here, Ying says: “We can see, from the lab measurements on core materials from reservoir or analogue rock samples from outcrops, the efficiency and the behaviour of EOR processes at a centimetre scale. And then we can move from core scale to the field scale and suggest how to implement the data obtained at the larger field scale to predict the field EOR potential.”

Addressing the knowledge gap between these different scales is one area where

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more work urgently is needed. IRIS and its dedicated group in Bergen is now using commercially available tools to address this and is now working on developing opensource reservoir modelling and optimisation methods.

IRIS’ EOR work – indeed, most of its research – mirrors that of North Sea operators’ need. “We study, for example, water shutoff, which is one of the main areas in our EOR portfolio,” Ying continues. “We of course work on polymers for mobility control, often in combination with surfactants. In addition, we also look

into the environmental aspects of chemical EOR, and the microbial EOR (MEOR).”

Another area is so-called “Smart Water.” Given the prevalence of seawater injection in most reservoirs, refining this, be it low-salinity sea water or low-sulphate water injection, has become a focus for the North Sea. For that reason research should continue unabated, even despite lower oil prices. “Because we use so much water we think that if we can manipulate it, maybe remove bad ions or add good ions for use in the reservoir, we think we can improve flooding efficiency.”

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This is partly cemented in the newly created Norwegian National IOR Centre, a partnership of academia and industry set up in 2013. Owned by the University of Stavanger, IRIS is one of the Centre’s biggest research contributors, together with Institute of Energy Technique (Ife) and a number of international partners. The centre is financed by Norwegian Oil and Energy Ministry, University of Stavanger and 10 major oil companies such as Statoil, BP, ConocoPhillips, and field service companies Schlumberger and Halliburton.

With the long-term financial

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commitment from these industrial partners and the Norwegian government, Roman says, “it allows us to go forward with more fundamental and long-term research, alongside with short-term solutions to solve the urgent needs of the industry.” It is this fundamental and applied research – IRIS talks of “long-term applied and theoretical R&D programmes” – which underpins the success of ongoing projects like EOR research. Centres such as these become all the more important when lower prices change industry priorities.

And priorities “have certainly changed with lowered oil price,” says Ying. “[Companies] are more short-term focused now. They want to do research projects with a 3- to 5-year horizon and projects which are directly applied to reducing costs.

Research which is more fundamental and requires longer research effort is harder to justify now.”

EOR and beyond Looking to the future, Roman has a few thoughts on where research could be directed next, in terms of EOR and beyond: “We’re also focusing a lot on decreasing uncertainty,” he affirms. “That essentially is going from looking at new-generation simulation tools to handle EOR better, and moving to better data utilisation.” The mantra, as InnovOil has seen in many cases in the past few years, is smarter working with existing technology alongside the development of new innovative ones.

“We have so much seismic and downhole tools which measure things at millisecond intervals,” Roman continues, “But incorporating and using it is complicated, because there is so much. Yet, when you put it all into the picture it can give you a much better perspective on what’s going on in the reservoir. Only by converting all the data into knowledge can one make sure that opportunities are not being missed.”

“It’s the technologies on the border of various knowledge bases which are becoming more important: these transferrable technologies,” he says. Ying highlights recent discussions with Pipes & Pumps, an association of the medicine, energy, aerospace and academic sectors which aims to look the potential for crossover technologies and knowledge.

There are, Roman and Ying note, “lots

of similarities between pumping oil from a well and pumping blood in a vein. We believe these areas will be very important for the future of the industries involved.”

Ultimately, Roman sees IRIS’ work as leading by example. Techniques pioneered and perfected in the North Sea will, one NEWSBASE

day, be used across the globe and, he says “We think that the North Sea can be a good example of what will happen.” With ambitious recovery rates, world-leading research and a new willingness to look for unconventional solutions, IRIS and its partners are setting the bar high. n

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Lateral thinking: laser drilling from ZerLux

Laser drilling has only become technically feasible within the last few years, but its accuracy, stability and the potential for increased production mean the industry should take note

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LTHOUGH innovation pushes the industry in new directions, the fundamental focus will always stay on drilling. Yet while rotary contact drilling remains the mainstay, new applications are entering the market.

While some are looking to drill with plasma, other cutting-edge bits of kit are also making their mark.

Lasers have long been considered for use in drilling, but the process has only become feasible and economic within the past decade or so, spurred on by enhancements in pulse energy, wavelengths and fibre efficiency. Seeing the opportunity, Hungarian firm ZerLux began developing laser applications and tools for oil and gas in 2010.

Although lasers are suited to a number of industry operations, improved oil recovery (IOR) operations via perforations are perhaps the most straightforward.

Extended perforations (a.k.a. laser-drilled laterals) employ a laser in place of a conventional explosive perforation, using it to drill short channels from the bore into the reservoir, and allowing more liquid to flow more economically into the well.

Zerlux sees it as an ideal technology to maximise production in shallow, thin,

Laser; 0 min

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Laser; 8 min

Machanical; 8 min

Comparative Flow Pattern Ananalysis: Laser vs Mechanically Drilled Hole mature or depleted oilfields with sandstone formations. It is also useful for deployment in formations where hydraulic fracturing could cause cementing failure, or where the process requires disproportionately higher investment and cost to pay out. With no weight-on-bit (WOB), there is no force applied to the cementing or the formation, so laser drilling is frequently faster and more stable than conventional alternatives.

How it works A typical system uses 30 kW of laser power

in the borehole, to drill 2-inch (50.8-mm) outer diameter holes, of up to around 80 feet (24 m) in length. These can be drilled straight through the casing, without the need for section milling, or to cut or remove production tubing.

It is controlled by the operator in real time, with video and spectroscopy feedback.

This offers faster tool-in and tool-out and reduced trip time overall, when compared to conventional drilling and milling – all of which reduce operating costs whilst increasing production.

The tool superheats the subsurface formation, melts the rock matrix and will remove the molten debris while the borehole is being drilled, meanwhile creating a durable borehole wall of adjustable permeability. Drilling debris, mostly disintegrated cement, steel and/or rock, is easily managed by the in-built removal system, more so than traditional swarf.

The lack of moving parts also means the system requires no drilling mud, no milling bits or motors that could create kicks or stalls, and eliminates fishing for stuck tools.

The laser bottom hole assembly (BHA) is designed for use with coiled tubing, and can also include multiple laser drilling heads, allowing for differing lateral bore sizes, all

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Rock

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housed in a small unit which takes up little space to operate downhole.

The system’s rate of penetration (ROP) is dependent on the available power source, but a combined, single trip will often be faster and more economical than separate section milling and drilling. Each laser has to be optimised for each formation, but a source of roughly 100 kW is needed on the surface to power a 30-kW laser downhole, owing to attenuation in the line.

Enhanced production Cost savings also come from other avoided expenditure, such as the time and cost of replacing damaged drill bits, other replacement parts and, more seriously, compromised formation integrity. By preserving the formation integrity while maximising the wellbore diameter, wells can produce more for longer periods.

The company estimates that well

Laser Drilled Hole

productivity is enhanced by approximately 200% when compared with conventional perforations, a figure borne out by recent studies from research firm AGR and other third-party assessments.

The technology is also suitable for use in high pressure/high temperature (HPHT) wells, both on- and offshore. Offshore, it also means complex drilling can be undertaken from smaller platforms, where higher-cost rigs are not technically or economically feasible.

ZerLux suggests that on average, the cost of drilling short laterals will equal that of conventional alternatives. But on balance, the increased stability, integrity and productivity mean laser drilled laterals for well completion may well be a more shrewd investment.

What next?

ZerLux is now preparing for the integration NEWSBASE

Induced Fractures and Increased Permeability Zone

and field testing of its extended perforation technology. June 2015 also saw the firm sign a new memorandum of understanding (MoU) with Delta SubSea (DSS) to co-operate on laser-based technology to remove hydrate deposits in pipelines.

This technique uses “focused warming” to equalise pressure and chemical flow across hydrate plugs in pipelines. This is important, DSS noted, because “depressurisation can cause the hydrate plug to detach and move uncontrollably inside the pipeline,” with severe consequences. The partners see this as an ideal tactic to tackle hydrate plugs, especially when used alongside chemical inhibitors. n Contact: Peter Bajcsi, COO

Tel: +36 20 339 8200 Email: p.bajcsi@zerlux.com Web: www.zerlux.com

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Enhanced oil sand extraction? Easy does it Is there a cleaner and more efficient way to extract bitumen from Canada’s oil sands?

Suncor Energy thinks the answer is ESEIEH, writes Tim Skelton

Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH)

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UNCOR Energy and its partners are pioneering a new application of an old technology that could revolutionise how oil sands are processed. They are using radio frequency (RF) heating to soften and loosen the oil, offering the potential to replace current energy-intensive extraction methods.

Existing methods for extracting bitumen from oil sands in Alberta in Western Canada have been criticised by environmental groups for being too dirty.

The simplest methods use open-cast extraction, removing the oil-laden sand wholesale from the ground and removing the hard bitumen at a remote location.

But this requires the intensive use of heavy digging equipment and haulers on the surface, which has a damaging impact on the landscape. Moreover, only around 20% of the region’s resources can be recovered using this method, as the remainder lie too deep below the surface.

In situ extraction technology using steam-assisted gravity (SAG) drainage plants are often heralded as cleaner alternatives to open-cast mining and more importantly can be used to exploit deeperlying resources. This method involves injecting hot steam into the ground, which softens the bitumen, loosening it sufficiently for it to be pumped out directly from the ground.

But while this does represent an improvement, as the surface area suffers from less scarring, there are other drawbacks. The process requires a lot of steam. This in turn creates large volumes

of wastewater. Furthermore, the burning of the fuel required to transform fresh water into steam is highly energy-intensive, and since this fuel is usually natural gas, it yields more greenhouse gas (GHG) per barrel of oil produced than even traditional open-cast mining methods.

The construction and maintenance of the onsite steam-generating plants often also involves clear cutting of forests.

Easy solution These problems have led the industry to hunt for alternatives to conventional extraction methods that are cheaper, more effective and leave less of an environmental footprint. One promising solution could come from an ongoing project called Enhanced Solvent Extraction Incorporating Electromagnetic Heating, or ESEIEH (pronounced “easy”) for short.

ESEIEH is currently being developed by partners Suncor, Devon, Nexen Energy and US communications company Harris, which pioneered the technology.

The partners say ESEIEH has the potential virtually to eliminate the need NEWSBASE

for water at in situ operations. Instead of steam, it uses patent-pending antenna technology developed by Harris. Radio waves heat and soften the oil sands electrically, in a manner not dissimilar to a giant underground microwave oven. A recyclable hydrocarbon solvent is then injected into the extraction zone to dilute and loosen the bitumen, with the minimum of energy requirements. It can then be retrieved via a horizontally drilled well, pumped to the surface and transported for further processing.

Harris first promoted its concept to the oil sands industry in 2009, but only now are the benefits becoming clearer to the sector. “This technology has been in use

by Harris for a number of decades, but never before applied to the production of bitumen,” Mark Bohm, Suncor’s manager for strategic in situ technology, told NewsBase. “The combined expertise of Harris and the industry know-how of our partners allowed us to come up with the concept of radio frequency and solvent extraction for in situ reservoirs.”

The group developing the project began

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exploring the possibilities for using this RF heating technology in 2011, when the first tests were carried out at Harris’s home base in Florida. The initial physical testing of the technology then took place in 2012 in a mine face at Suncor’s Steepbank facility, north of Fort McMurray in northeast Alberta. “That stage of testing proved that the radio frequencies could heat a bitumen reservoir,” Bohm said. “The results from this phase were encouraging, indicating that RF could be used effectively to heat bitumen in situ.”

The early testing phase paved the way for a scaled-up ESEIEH pilot scheme – the first production test of the technology on actual subterranean oil sands deposits.

This went into operation in mid-July this year, at Suncor’s Dover test site, also north of Fort McMurray. The test project – which is scheduled to run for around 24 months – is expected to cost in the region C$44 million (US$33.59 million). The funding came from the ESEIEH partners, as well as from the Canadian Climate Change and Emissions Management Corp.

(CCEMC).

“For the current phase we are undertaking at the Dover site, we are testing within an in situ reservoir in a 100-metre well pair incorporating propane as a solvent into the process,” Bohm said.

“The operations phase of the pilot has started, and we will be evaluating the results over the next two years.”

Bohm stressed that the pilot project was still in its very early stages, and as such there are no firm results yet. But he said the process as a whole had been encouraging. “The team has really come together successfully to start the field test and we’re excited to learn more about the potential of this technology,” he told NewsBase. “As this is a pilot, we’re continuing to refine the approach as to how to operate the subsurface and surface equipment. We’ll have more to report on our successes and challenges later.”

Scaling up If the pilot proves to be a success, the group anticipates scaling things up in the next stage. “If this phase is successful, we will move onto a full-scale commercial NEWSBASE

demonstration plant that will incorporate multiple full-length well pairs,” Bohm said.

The hope is that the ESEIEH process will result in a reduction of up to 75% in energy requirements per unit volume of oil extracted. This, along with the complete elimination of the need for water in the in situ recovery process, is anticipated to improve environmental performance by significantly reducing GHG emissions, and also increase efficiency and reduce the capital expenditure required compared to traditional extraction processes.

Moreover, the physical footprint of the well site can be reduced, as the need for a space-consuming steam generation plant is removed.

Should it prove commercially viable, ESEIEH radio frequency extraction technology could revolutionise oil sands extraction. It offers a cheaper and more efficient solution for oil companies, whilst also being considerably more environmentally friendly than existing methods. The industry will be watching the progress of the ESEIEH testing phase closely. n

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Utility players THE BEST OF 2015

InnovOil talks to Utility ROV Services about the engineering behind its specialist subsea equipment for renewables and decommissioning

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HILE subsea equipment can now perform more functions than ever before, the industry lacks a true workhorse.

Different classes of ROVs are, of course, tasked with different roles, but while these can be re-engineered, re-tooled and redeployed, this all adds time and money.

Enter an ingenious Scottish firm. With its roots in a family-run commercial cargo recovery business, Utility ROV Services’ managing director Patrick Crawford has helped develop a versatile and flexible set of winch-deployed tools for subsea work – a concept explained to InnovOil as “a subsea tractor.”

Formed in November 2013, the launch of the Glenrothes-based company was the culmination of around seven years’ worth of development and deployment, producing a number of innovative tools used to tackle the unique challenges posed by sunken ships and offshore structures. These jobs saw the firm continuously design and build its own bespoke equipment – the result of which is the UTROV system.

It allows the team to undertake a range of industry tasks, from clearance, trenching and construction to concrete mattress recovery, subsea demolition and decommissioning.

Crawford explains that his approach is grounded by experience in the salvage market: “We’ve got to cover the whole project and have to be able to try and do as many jobs as possible, as cost-effectively as possible… So we saw the opportunity in the industry, and particularly decommissioning as an inroad into the oil and gas market, in terms of providing new technology.”

The right tools for the job The Utility ROV unit itself (UTROV) is essentially a subsea tool carrier. Its primary functions are to transfer the lift capacity of its umbilical winch and to provide common connections for the electrics, hydraulics and comms of the various tools. The system is controlled via a mobile control system housed in a 10-ft (3-metre) shipping container, or in an alternative location if space is tight.

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At roughly six cubic metres, its footprint remains fairly small. The 2.6 tonne unit is suspended by the umbilical, but also has 4 vectored thrusters which allow it to move in a 15-metre radius when subsea, dependent on water depth. It is rated for work at depths of up to 3,000 metres – though it can work deeper if its lights and camera are changed.

A 35 tonne A-frame winch mounted at the stern of the vessel is used to deploy and recover the UT ROV. The system will work in a 3-metre swell and in currents of up to 3 knots, as tension controls on the winch mean it will heave and render automatically to keep the unit steady whilst subsurface.

This unit provides a base for a range of tools to be deployed. The bulk of UT ROV tools are comprised of 3 modified grabs from land-based excavator systems.

Their use onshore means they have been extensively tried and tested, and are up to the task of working in the harsh subsea environment.

The Tine Grab is a general-purpose grab to handle any material. Sets of legs are available with or without orange peel.

Previous deployments have seen this used for wreck demolition and material recovery. The Clam Shell Grab is used for bulk material handling, and is available with or without teeth for use with denser materials.

Meanwhile, the Shear Grab is a dedicated to subsea demolition, and is ideal for dismantling structures and/or cutting pipelines. It is deployable in two frames: one is remotely movable between vertical and horizontal positions, while another is fixed on its side for use in cutting vertical structures.

The MFE, or mass-flow excavation tool, was developed by the team to perform noncontact dredging. The max 250-RPM unit offers an efficient method of clearing and removing sediment from subsea structures without damaging them – a task the salvage team is well-versed in.

Owing to the large hydraulic flow needed to operate, traditional MFEs are often powered directly from the surface. The distance between the two often results in a loss of power in the hydraulic hoses, all of which makes for an inefficient system

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THE BEST OF 2015

The MFE rises from the deep unsuitable for use in deeper water. The inbuilt hydraulic power of the UTROV solves this problem since the power is at source Heavy duty lighting and camera mountings are fitted onto each of the tools as well as the UTROV, giving the operator specific and general views to carry out his work safely and effectively.

On deck, the system is stored and transported in several containers which also house the control system, power and workshop. These are can be easily moved by road or air, before being loaded onto a suitable vessel of opportunity and configured as required.

Plus shipping Unsurprisingly, the team has had a busy year. An agreement made early in 2015 saw a joint venture between the company and Fletcher Shipping to install a system permanently on one of the latter’s vessels.

The FS Pegasus, an 84-metre, Ulsteinbuilt 745 platform supply vessel (PSV), is now fitted with a full UT ROV system.

Owing to the small footprint of the UT ROV and the high loading capacity of the deck, the vessel is a versatile platform for subsea work – and at a much lower per-day cost than other options.

“If you look at the costs of a project,” Crawford says, “It’s all vessel costs. Using an offshore construction vessel or a

dive support vessel will incur a day rate somewhere in the region of six times higher than that of a PSV. The UTROV system exploits this and capitalises upon the lower cost vessel.”

The deck features a single deck crane for use with the UT ROV, as well as two 10 tonne tugger winches and the ship’s 2 tonne crane. Additional deck cranes can then be fitted as required –the FS Pegasus has the capability to deploy a full campaign of 300 subsea mattresses without returning to port, thanks to a configuration of lifting frames.

Carrying all the necessary UT ROV tools in the one vessel also means projects can often be completed in one trip. In addition to the vessel’s crew, 14 berths are available to house client staff, survey teams.

The vessel choice and the capabilities of the UT ROV tools are all about providing the most flexibility at a competitive price – and this requires a holistic approach to the tasks in hand. “It’s about looking at the whole system, not individual aspects of it – and that’s how you reduce costs,” Crawford says. “If you don’t understand the whole system, you generate a problem by using the component which might be the best component on an isolated basis but isn’t the best for the whole system.”

Future plans Forging links with other innovators has been NEWSBASE

key to Crawford’s strategy, and the expertise and help of companies like Fletcher Shipping “have been a big support,” he says.

But in what has already been a busy year, Utility ROV Services still has new avenues – business and technological – to explore.

“I designed a mattress recovery system which we’re going to start building and testing just as soon as I get this first contract under my belt and under way,” he enthuses.

A recent salvage operation offshore Ireland also gave the team cause for some unexpected innovation. Owing to “some pretty terrible weather and some pretty bad luck” the umbilical was snagged and severed while working, leaving the UTROV and one of the tools inside the wreck.

Despite the setback and a hurried trip back to their Fife base: “In 4 days we designed, built and got working a whole new system” capable of retrieving the lost equipment, he says. Deploying it within a matter of days, not only was the tool recovered, but Crawford and his team had also engineered “a brand new bit of kit.”

This spirit of innovation runs through the now 12-strong company, but is always balanced with the cost-conscious view of a salvage outfit. Future changes to the equipment may even see some pieces of equipment scaled down, enabling the UTROV to be more agile and responsive to particular tasks. “I personally think we’ve way over-spec’d the machine we have for the operations we are currently tendering for,” he suggests. “By using smaller vessels, we can offer again a cost saving to the end user – because ultimately for shifting rocks, you don’t need a machine like we have.”

From here, the company has the enviable position of being almost too busy to cope with interest. The next year will see new equipment built and more opportunities to prove the system’s capability to the various sectors of the offshore industry. “We want to show that this method works and that it’s cost-effective and productive,” Crawford says. n Contact: Craig Roberts

Tel: +44 (0) 1592 773 344 Email: enquiries@utrov.com Web: www.utrov.com

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Big power, little package THE BEST OF 2015

Teledyne Seabotix profiles its solution-driven options for the subsea and offshore industries, including the development of the new, patent-pending Storage Tank Surveyor™ system

I

N February of this year, we covered Teledyne Seabotix’s small, remotely operated vehicle systems, as well as its intriguing new Storage Tank Surveyor™ concept. The former is a versatile ROV system with multiple applications and payload options, while the latter – still in qualification – could offer operators a new cost-effective method for tank inspection and monitoring.

We caught up with Teledyne Seabotix’s Sandy Kennedy for an update on both the vLBV and the STS. Thrust-have At the very heart of its offshore solutions lies the vectored Little Benthic Vehicle (vLBV) ROV system which can be configured for depths of 300 metres, 950m, 2,000m or 4,000m.

The vLBV’s vectored thruster configuration provides precise control in all directions, making it ideal for use offshore in demanding conditions. A bollard thrust of 18.1-22.5 kg (40-50 lb) force is available to the operator. The thruster vector angle is adjustable, allowing for numerous set-up options in order to meet differing conditions and applications. The dual-vertical thruster configuration offers greater control and roll stabilisation than single-vertical thruster ROV systems, making the vLBV an extremely stable and precisely manoeuvrable sensor platform.

Weighing only 18 kg (40 lb) in standard configuration, the power-to-weight ratio is optimised for conditions that test much larger, more powerful vehicles. One of the greatest challenges to ROV operators is the constant effect of water current dragging on the lengths of heavy tether required to

supply vehicle power and carry control signals, feedback and sensor data to and from the surface. The vLBV utilises an 8.9mm (0.35-inch) nominal diameter tether, thus minimising the effects of drag.

Depending on the length of tether required, the vLBV can operate with a copper or a combination copper and fibre optic telemetry, providing multiple video capabilities – including HD – serial port connections and Ethernet link. A suite of interchangeable sensors and tooling combinations can therefore be utilised, either on the vehicle itself or via “skids,” which can be quickly changed as required.

Additionally, a sensor fusion autonomy package called SmartFlight™ is available for the vLBV. SmartFlight offers waypoint navigation, pre-programmed search, stationkeeping and target data import from other vehicles.

A ten-thruster version – featuring six verticals – can also be used for the deployment and retrieval of sensors or other payload weighing in excess of 18 kg (40 lb).

Space saving The versatility of the Teledyne SeaBotix vLBV provides a number of solutions to commonly encountered challenges.

First of all, there is the time, effort, and

Complete vLBV system ready for offshore operations

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cost implication of ROV operations, as expensive launch and recovery equipment can take up precious space on vessels and platforms. This is true even for simple tasks: for example, the latest iteration of the US Environmental Protection Agency’s (EPA) Code of Federal Regulations (CFR) 40 requires mandatory weekly inspection of sea chest water-cooling intakes on all new offshore platforms and structures.

A potential solution is the two-person portable vLBV, operated direct from its ruggedised transit case and deployed/ retrieved via a davit, or palletised winch and crane. Alternatively, the ROV can be deployed and controlled from a 10ft (3m) ISO container, which can be moved swiftly on or between platforms or deployed from a vessel of opportunity. There is also a self-contained 20ft (6m) model, featuring an active, heave-compensated winch and boom deployment for deepwater operations, up to 4,000m.

The modular design of the vLBV also allows for a tracked crawler skid to be integrated quickly, allowing the entire ROV system to adhere to structures and vessel hulls for more detailed inspections, in very high surrounding current.

In addition to its visual inspection capability, the system can also be fitted with ultra-short baseline (USBL) tracking, obstacle avoidance or high-resolution imaging sonars for turbid conditions, grabber/cutter combinations, water sampling, leak detection, laser metrology and a range of non-destructive testing (NDT) sensors, including cathodic protection (CP) probe, ultrasonic thickness (UT) gauge, or a flooded member detection (FMD) tool.

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THE BEST OF 2015 vLBC with crawler skid, USBL positioning beacon and imaging sonar

A new perspective Hydraulic work-class ROV systems are a capable and vital asset for subsea construction, salvage, completion and heavy duty intervention tasks. However, their sheer size can prohibit access to delicate subsea structures to observe surfaces or complete other simple NDT/ intervention tasks.

Furthermore, work on precise and complex operations requires dexterity and subtle movement using large manipulators and other hydraulic tooling, necessitating additional perspectives for the pilot, other than those of the on-board or manipulator wrist cameras. In these situations, an additional ROV spread may be needed to provide a third-person perspective, which can double the cost – and risk – of the procedure.

The vLBV, meanwhile, can be mounted inside a garage or tether management system (TMS), along with a subsea-level wind spooling winch for pay-out and retrieval of the 200m vLBV excursion tether. This entire unit can be mounted into a skid on the work-class host vehicle or its TMS. The unit is then interfaced through an intermediate electronics bottle, transferring control signals and sensor data via the host ROV umbilical to the topside control room. This permits 360-degree safety cover around the work-class system

and a third-person perspective, allowing access to the tightest of locations.

This same solution can be integrated into unmanned autonomous surface vehicles (ASVs), which will soon be providing lowcost survey capability to the wider offshore industry.

Storage Tank Surveyor™ [http://www. sonasearch.com/storage-tank-surveyor.html] There are a substantial number of onshore fuel and other liquid storage tanks globally. There are also approximately 350 floating storage structures – mainly floating production, storage and offloading (FPSO) vessels – which have large oil storage tanks on board. To survey otherwise inaccessible floor and internal wall thicknesses and structural welds, these tanks first have to be emptied, at huge cost. This is estimated at around US$5 million over the one- to three-month process. Personnel in personal protective equipment (PPE) must then carry out a survey, by hand, before the tanks are re-filled. Unsurprisingly, major operators are keen to find a more cost-effective solution.

The Storage Tank Surveyor™ (STS) is a partnership between Teledyne SeaBotix and Sonasearch of Redmond, Washington State, US. By mounting the STS acoustic camera on a vLBV with crawler attachment, the entire system can be deployed into a liquidfilled steel tank to conduct a precise survey of its floor and vertical walls.

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Using phased array, 3-D imaging, the STS incorporates an electronically beamsteered, multi-element scanning head, measuring the tank thickness and weld integrity at an ultra-high resolution of up to 113 microns and mapping returns passing bi-directionally through the tank wall. The result is an inspection point with accuracy equal to or better than 6.35mm (¼ inch) that can reliably detect corrosion areas measuring less than 25.4mm (1 inch) in diameter. This can provide an accurate prediction of when corrosion has reached the point of intervention or replacement.

During a proof of concept trial earlier in 2014 for a leading oil major, an STS system was deployed in a large water tank and carried out a successful survey.

Measurements using the STS, when compared to a known control sample plate, gave results with an accuracy of ± 0.001mm.

The Storage Tank Surveyor is currently being certified for operation in Class 1, Division 1 and Zone 0 environments for operation in combustible fluids and incorporating a precise positioning system for inertial navigation and 100% tank mapping, before full trials in fuel tanks commence.

The challenges of completing such surveys in an FPSO full of crude are significant. However, the proof of concept in water tanks alone is a major solution to a rather long and expensive process and already key figures in the offshore integrity management community are lending their support and crucial input to this project.

With oil prices now troublingly low, reducing costs in capital equipment and personnel is becoming even more critical.

The low-cost, modular, creative approach of the Teledyne SeaBotix vLBV design is one that will continue to provide more than just these three solutions for some of the most difficult subsea projects, whilst ultimately saving money for the client. n Contact: Alasdair Murrie

Tel: +1 619 450 4000 Email: alasdair.murrie@teledyne.com Web: www.seabotix.com

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Control + Print THE BEST OF 2015

Jeremy Bowden reports on a new JIP which could see the oil and gas industry embrace the potential of 3-D printing

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AST month TWI and Lloyd’s Register Energy announced that they would embark on a joint industry project (JIP) to develop 3-D printing techniques for the offshore oil and gas sector. The 18-month project is expected to attract considerable interest from companies worldwide looking to collaborate and to gain early adoption of ‘approved’ additive manufacturing (AM) – or 3-D printing – for their products.

The project involves the certification of laser powder additive-manufactured components for industrial adoption in the energy and offshore sectors. The additive manufacturing market is forecast to almost quadruple in the next seven years, according to TWI, while Lloyd’s Register Energy’s 2014 Technology Radar survey suggested that AM would have a major impact on the oil and gas industry in particular within the next five years.

3-D printing is a direct digital manufacturing process by which a component is produced layer by layer from 3-D digital data without the use

of machining, moulding or casting.

Each layer is subsequently recreated by depositing powder layers, one on top of the other and melting their surface by scanning a laser beam over the powder bed. The technique has developed rapidly over the last ten years, and although the benefits apply equally to numerous industries, applications in the energy and offshore sectors are currently still at a relatively nascent stage.

Precision engineering TWI’s project leader, Amanda Allison, told InnovOil that the sort of manufactured products best suited to the technique were small precision-engineered components that can then be fitted together into more complex machines or facilities. It is most suitable for highvalue parts, produced in low volumes and manufactured from high-value material.

These include products difficult to manufacture by conventional processes – complex organic shapes, re-entrant angles and internal cavities, for example.

3-D printer on display at Robot and Makers Milano Show, event dedicated to robotics NEWSBASE

Likewise, it can be very beneficial if the level of waste, particularly of expensive materials, is high when using conventional machining.

The scale of component that can be produced is limited by the size of the machine, so large pieces of equipment are not ideally suited. Larger 3-D printing machines are correspondingly more expensive, and so production of large items carries additional cost.

Allison said the technology the JIP is evaluating could support two size levels.

The first, selective laser melting (SLM), uses AM software to slice a 3-D CAD model and has a typical build chamber volume of 250mm x 250mm x 300mm.

The second technique is laser metal deposition (LMD), which uses a movable powder nozzle and laser beam operated by a robotic or gantry-based motion system. The build envelope is dictated by the size of the gantry or robot; while the typical range of this system is 2,000mm x 2,000mm x 2,000mm, this is by no means a limit.

In principle, it means that replacement parts could be generated on site as needed, but current technology requires application assessment on a case-bycase basis, she added. Once established, 3-D printing should help the industry to produce more replacement equipment on site as it is required, rather than having to have it ordered in advance and shipped in. This should reduce logistics costs, and would reduce the need to maintain large inventories of replacement parts, in turn making rigs and other installations more self-sufficient. When twinned with other automated technologies, this could extend the already-growing potential for remote operations and maintenance.

Allison said that other longer-term benefits for the oil and gas sector could include reduced manufacturing and maintenance costs generally, shorter lead times on complex components and the opportunity to manufacture components to more novel designs and in an increased range of materials. In

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THE BEST OF 2015 3-D printing technology can be used to manufacture complex components

addition, companies can expect to extend the life of existing infrastructure with new components and increased durability through the reduction of maintenance cycles and lower repair costs.

Complex components While 3-D printing techniques are relatively new to offshore oil and gas, additive manufacturing is widely adopted by the defence and aerospace industry, where its ability to create complex metal parts with a high level of precision, reduced weight and high material utilisation makes it a viable method of constructing components for turbines and engines.

In the new application of the techniques to the offshore and marine sectors, TWI and Lloyd’s Register Energy are planning to research and develop real-world additive manufacturing practices and create new industry product certification guidelines. This should pave the way for more widespread adoption of additive manufacturing technology, while at the same time assisting industry

in determining how best to tap into its potential.

TWI and Lloyd’s Register Energy are members of an ISO working group developing the 3-D manufacturing standards. However, the standards are still several years away from the adoption stage, and there is no provision in existing standards for the certification of parts produced using the new 3-D printing technology. TWI added that the JIP was aiming to deliver evidence-based certification guidelines for laser powder additive manufactured parts within 18 months.

Although the industry has its own exacting safety requirements, the use of 3-D printing in both aerospace and defence is reassuring for operators concerned about its practicability and reliability.

Industry collaboration The partners believe that collaboration is the primary driver for sustainable growth in new manufacturing technology for the energy and offshore industries. Each NEWSBASE

sponsor on the project will be invited to contribute a detailed component design to form the subject of a case study.

Each component will then be taken from concept through to completion, ultimately providing the sponsor with a conditionally certified part that meets industrial requirements for quality, safety and consistency, and which is qualified ready for market introduction.

Sponsors will also benefit from improved insight into laser powder AM processes and practices, and a reduced cost of certification thanks to the combined processing and manufacturing certification expertise of the JIP partners.

TWI is a formidable lead for the project, having amassed considerable experience in AM in developing both SLM and SLM and LMD processes for many years. With the addition of Lloyd’s Register Energy’s expertise in product certification and its strong links to international oil and gas producers, the project could be a breakthrough in terms of reaching global codes, standards and regulations. n

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Annual 2015

Divine intervention THE BEST OF 2015

GA Drilling’s unique non-contact PLASMABIT system offers a new, rig-less technology for section milling, which could change the way operators approach P&A

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HE costs of decommissioning are hard to face with oil at $100 per barrel, but at $60 and below they are painful. Despite exposure to this looming issue, many operators have not yet prepared a strategy. Asset retirement is still being planned around existing technology, rather than innovations – many of which could alter the outlook dramatically.

As seen earlier in this issue, by far the greatest outlay for decommissioning lies in well plug and abandonment (P&A), a process which represents about 40% of total costs.

Onshore this remains fairly cheap; costs may run from a few hundred dollars to around $100,000. Offshore however, is a different story. Oil & Gas UK forecasts that P&A on the UKCS is expected to cost around £4.5 billion before 2022 – over twice as much topside removal, at £2.1 bn.

Low oil prices can make this worse, as operators are more reluctant to commit funds. But whether the industry wants to acknowledge the problem now or not, the inbound P&A storm can be tackled with new equipment and a fresh approach. Most of all, operators also want more certainty on how much P&A will cost.

The problem Most wells are plugged at the lowest possible cost, in line with minimum requirements set by local regulators.

However, correctly plugging a well limits the risk of costs later down the line, reducing the potential for fluid or gas leakage. In this sense, operators can see that the ROI on decommissioning lies with the knowledge that the well is abandoned safely, without threat to their future operations.

So far, the industry has been reliant on mechanical and rotary technologies to do this. In P&A, the well tubing is pulled and part of the casing is either pulled or section milled in order to install a permanent plug.

Currently, the production tree and tubing must also be removed, one of the most time-consuming processes of the whole P&A operation.

PLASMABIT section milling in water

Section milling – the process of removing the steel and cement casing– is one area where gains can be made. A recurring problem is that the traditional methods of section milling are timeconsuming, unreliable and generate problematic swarf.

Rotary contact milling also has a tendency to need multiple fishing jobs – retrieving lost or stuck equipment downhole. Furthermore, during well-cleaning jobs – pumping fluid down hole to remove particles and swarf – the milled material can interfere with the blow out preventer (BOP), and large particles can flow around the well, damaging it and other equipment.

PLASMABIT Since 2013, GA Drilling has led a joint industry project (JIP) to develop PLASMABIT – a milling tool for P&A. Instead of a conventional rotary contact drill, PLASMABIT generates heatflow using an electrical arc, spinning at up to 800 rotations per second (48,000 rpm).

Aside from the electrical arc, there are no mechanically moving components in the bit. The extreme temperature (up to around 5,700°C) of the directed thermal NEWSBASE

electric plasma arc melts and disintegrates metals, rocks and cement, all without direct contact. Meanwhile, temperatures outside of the arc stay more manageable and are easily resisted by the wolframium-copper composite structure. This directed heat makes PLASMABIT particularly effective for well interventions and section milling.

PLASMABIT melts steel and cement rapidly, enabling a higher rate of penetration (ROP) when drilling and milling. Non-contact milling also means PLASMABIT is reliable; no wear and tear on a mechanical tool limits the cost of damaged equipment, stuck tools and makes the need for tripping virtually redundant. The result, GA Drilling claims, is significantly more uptime and a cost saving to operators.

PLASMABIT can operate continuously, limited only by the lifetime of the system’s electrodes. These are designed to run for tens – potentially up to hundreds – of hours, meaning milling can proceed almost uninterrupted.

Rig issue In the past, offshore P&A has usually required a rig. PLASMABIT is designed

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THE BEST OF 2015 The milled material is smaller than swarf

360 days

Conventional P&A process 200 days

PLASMABIT P&A process 125 days

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|

70 days

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90 days

250 days

35 days

for use with coiled tubing system – saving space and the logistical problems of larger equipment. This means it can also be deployed from a light well intervention vessel (LWIV), again reducing the need for larger, heavier, machinery, and reducing costs by around 50-60% when compared with the day rate of a rig.

The system requires a power capacity of around 250 kW, provided via power cables in the tubing and well within the range available to intervention vessels.

The use of coiled tubing also means that sensors within the system can provide realtime data acquisition of milled material, providing the control centre with detailed information its on composition.

Furthermore, section milling with PLASMABIT produces small particles of material, rather than swarf. This helps to ensure the integrity of the BOP and other components, limiting failures and damage caused by flyaway material. Coupled with the lower frequency of stuck tools and the smaller size of cutting produced, this offers increased safety, lowering overall reported accident rates and giving operators an additional edge when competing for contracts.

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90 days

PLASMABIT is designed to compliment existing equipment and infrastructure, but remains smaller and lighter than conventional alternatives and requires fewer personnel to operate.

Meanwhile, operations can be controlled remotely from a command centre.

Time saving A recent report for a decommissioning operation in the UKCS – Tullow’s Orwell wet gas field – pegged P&A time at 12 months. Accounting for the availability of suitable heavy equipment, vessels and rigs – even in a possible future environment where these are more freely available than now– adds to the lead time of a project.

Surveys of PLASMABIT JIP members suggested that almost 80% of time spent on P&A jobs relates to casing removal and preparing the well for plugging. Milling using PLASMABIT could accelerate this process dramatically.

PLASMABIT is also able to work via subsea production trees and tubing, again saving time when completing their removal operations. Moreover, this approach protects the existing assets and enables the shift from permanent to temporary P&A. NEWSBASE

The included table (see table) highlights particular areas in which the use of PLASMABIT can speed up the process, including current operations which are rendered unnecessary.

Although still at the precommercialisation stage, GA Drilling hopes that overall, from planning to execution, PLASMABIT could lower the cost of the P&A process by up to 50%.

Ready to go Major operators and service companies from Western Europe, the Middle East and US are already involved in the PLASMABIT JIP. But GA Drilling is still looking to engage more companies in order to speed up commercialisation and deployment.

The company has successfully undertaken both casing and cement removal with the PLASMABIT milling technique in water. To date, a prototype has milled one layer of a cement casing structure, and work is now underway to expand this to a second layer of casing.

Currently, PLASMABIT has reached level 3 in the API 17N Technology Readiness Level (TRL) index, where the functionality has been demonstrated through testing over a limited range of operating conditions. With a prototype now manufactured, the current target is for the project to reach level 4 – Fullscale prototype built and technology qualified through testing in intended environment– by the end of 2016. Full commercialisation would then follow in 2017.

Despite low prices exerting pressure on R&D budgets worldwide, the opportunity to speed and streamline P&A could provide some much-needed reassurance for companies concerned with the costs of decommissioning. n Contact: Slavomir Jankovic,

Chief Business Development Officer Tel: +421 (0)905 617 192 Email: slavomir.jankovic@gadrilling.com Web: www.gadrilling.com

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THE BEST OF 2015

Looking for a breakthrough

Head of Clariant Oil Services, Doug Hayes, explains the company’s innovation philosophy and how this adds value to customer operations

“B

ETTER, faster and more efficient.” This, according to chemical firm Clariant, is the philosophy by which it approaches innovation. While not unique to the oil and gas industry, it is a helpful maxim to guide both blue-sky innovation and market-led product development – not least during the pressured times in which the industry finds itself.

Clariant’s head of Oil Services, Doug Hayes, agrees that in tough times, companies have to be bolder and more innovative. “We’re very much committed to the innovation side of the business.

Some companies may have held back a bit and really focused just on operational efficiencies, but we feel like Clariant is taking the lead, certainly in the chemical sector of the oil business, and saying: ‘You know what, we’re going to invest more in innovation.’”

While all operators are essentially chasing the same goal – cost-effectiveness – the innovation and strategy behind this tends to take one of two approaches. “It can play out in just cost reductions, looking at a change in the chemistry that’s lower cost and a high-efficiency application,” Hayes says. “Or it can play out as looking at it completely differently and taking a novel approach to how we address a

problem, either from an application or from a product point of view.”

Joining in at Johan Most recently, and featured in the September edition of InnovOil, is Clariant’s agreement with Statoil to supply production chemicals for its Johan Sverdrup project. The deal was partly the result of a long history of collaboration between the two firms, Hayes says. “For the last 10 or 15 years with Statoil we’ve been a primary supplier of production chemical additives and services and so we’ve developed a very good working relationship… We do joint development activities with applications for products that enhance production efficiency and they rely, to some degree, on our innovation and research group to help solve some of the key issues with production and optimise production efficiency.”

The breadth and complexity of the project is likely to involve closer cooperation than ever before. “It’s probably a little more upfront in the design phase than we’ve typically seen with a lot of operators,” Hayes explains. “A lot of operators like to do that work before they pull in their suppliers. In this case, because we have such a close working relationship with Statoil, they’ve pulled us NEWSBASE

in and involved our engineers upfront.”

This hands-on approach will see the firm engaged in developing not only the products, but the systems, the injection processes and the application techniques.

“In some cases, it may even involve modifications of current products so that they’re more effective on that platform when it starts up,” he suggests.

While this level of integration might be unusual for the industry, it is not a departure from Clariant’s approach to collaborative projects. Innovation projects rely on clear co-operation: “If you’re in isolation, you have a very difficult time really solving the problem of your business partners,” Hayes adds.

Global challenges Yet Sverdrup is not the only technical feat – globally, there is no shortage of challenges.

Hayes points to issues encountered by Canadian operators in need of new ways to treat heavy oil, while shale producers look to innovative scrubbing technologies to tackle hydrogen sulphide in the Eagle Ford formation. Deepwater drilling in the Gulf of Mexico and Brazil also represent frontiers for chemical innovation.

Hayes comments: “With high pressure/ high temperature [HPHT] the type of application required to run capillary

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THE BEST OF 2015

streams and umbilical streams down through very cool water, you have to have a very high-spec product that will meet certain qualifications, not just for technical performance [but] purely an application point of view. It’s very much an area where we do a lot of innovation.”

It is also a region which is still in need of new solutions – the company is working on refining the second and third generation of successful products, largely because, Hayes says, “we feel like the ‘apex technology’ is not fully developed.” While incremental improvements can sometimes be made in a matter of months, more fundamental work and game-changing chemical creation can take a much longer timeframe, often up to three or four years.

At present, the company’s longer-term research is examining multiple aspects of enhanced oil recovery (EOR), including everything from additives and surfactants for sweep efficiency and stimulation to solutions to clean up and raise productivity from older wells. Again, Hayes makes the point that these efforts are collaborative: “If we’re working with an operator in a joint development and perhaps with a polymer provider, we’re able to come up with the right chemistry and application techniques to recover an additional % of oil from the reservoir.”

Staying on the cutting edge Within the challenge of this kind of long-term research lie the roots of new innovation. In improving and refining a chemical platform, new and interesting discoveries are often made. “It really is sometimes the result of trying to improve the efficacy of an existing product and then we come upon some possibilities when building off of that platform and that can lead to that next level of innovation,” he says.

“We’re also looking at some, I would call them ‘breakthrough-type’ technologies, but those are longer-term projects,” he adds, “They’re a little more high-risk, but we always like to be out there on the perimeter, looking at what’s new, what’s unusual.” Key to this process is input from the Clariant Excellence Innovation group, a troupe of “black belts” working between Clariant business lines, on the lookout for interesting synergies or novel applications. This is cemented by a global innovation centre based in Frankfurt, where “there are about 500 scientists we have access to, so we’re able to look at what we’re doing in the oil sector that could have some correlation to what’s going on in other Clariant business units from a chemistry point of view.”

Using its global workforce to solve unusual problems is also an interesting NEWSBASE

way to foster new innovation, and taking personnel from one environment and applying their expertise to another can often produce some unexpected results.

“When we bring in this expertise from overseas, they’re not bound by the local application bias, if you will,” Hayes enthuses, “They step out of the box, they look at it completely different. The only challenge is that there are people who want to hire the person you just flew in from across the world because of their unique view on problem solving!”

One thing made clear is that Clariant’s approach to innovation is as much philosophical as it is market-driven. “We have to go into this from an innovation point of view,” Hayes impresses, “I think we have to stay right out there on the cutting edge in this industry to be able to deliver to what the operators expect.

Because if we just do the same thing that our competitors have been doing, and try to shave just a little bit of money off of the cost, we really didn’t solve the real problem.” This is a bold view, and one which is all the more admirable in an already difficult price environment.

But with no shortage of problems, and a constant demand for better, faster and more efficient solutions, it is a strategy which will surely pay off.. n

page 42

InnovOil

Annual 2015

THE BEST OF 2015

The power and the Glori Using the natural bacteria in a reservoir, Glori Energy’s microbial EOR technology – Activated Environment for the Recovery of Oil (AERO) – could change the fortunes of mature fields worldwide

F

ROM this issue of InnovOil alone we can see that approaches to improved and enhanced oil recovery (IOR/EOR) are diverse.

Some depend on large infrastructural investments, some depend on the availability of additional resource and some require oil prices far above today’s new normal – sometimes expenditures up to US$50 per barrel. The solutions which show the greatest promise are therefore those which require none of these conditions; they should be inexpensive, proven and deployable in reservoirs with a range of characteristics.

Many may not believe that microbial EOR (MEOR) can be any of these things.

Attempts in the past have been patchy, and some operators may be wary of taking perceived risky strategies with a reservoir already in decline. Yet Glori Energy’s Activated Environment for the Recovery of Oil (AERO) technology is entirely different to techniques which have gone before, and the team behind it is keen to show just what it can do.

Where previous MEOR efforts have focused on introducing helpful – yet alien – microbes to mature reservoirs, Houstonbased Glori reversed the problem.

Uniquely, by encouraging and cultivating the most useful indigenous bacteria already present in the reservoir, its biologists and engineers have enabled a remarkably effective method of improving oil recovery in waterflooded, sandstone reservoirs.

“More interestingly,” Glori CTO Michael Pavia explains, “Rather than have

[bacteria] make something like a gas or an acid, we actually get them to behave as a surfactant – not excrete a surfactant into the oil, but actually behave as a surfactant themselves.” The microbes also thrive where the oil is trapped, resulting in changes to water flow patterns at the reservoir’s pore-throat level, and freeing up more pathways for oil flow.

The results of its work over the past decade or so have led to decreased decline rates, increased reserves and –most importantly for an EOR technique – increased oil production. Glori is confident that it can offer incremental recovery of an NEWSBASE

additional 9-12% of original oil in place in mature fields. By introducing AERO from the beginning of waterflood process, it will slow down the increase of water cut and ultimately enable even higher oil production.

Ready for the flood AERO is also amongst the most inexpensive EOR systems to operate.

The indigenous bacteria themselves are naturally suited to each reservoir, meaning they are unlikely to perish. Neither are they costly to produce or maintain, given the relatively low OPEX of the nutrients

Annual 2015

InnovOil

page 43

THE BEST OF 2015 Below: A Glori field technician collects quality control samples from an injection well under continuous AERO treatment

needed to encourage their growth.

Likewise, the system can also be set up with minimal changes to the existing waterflood facilities and a very small footprint. The equipment is a simple injection skid with associated pumps and compressors, “around 6 feet by 9 feet [1.8m x 2.75 m] and essentially plug and play,” an appealing factor for space- and weightconscious platform operators. Injection water must be below 14% salinity, meaning the system is suitable for the majority of on- and offshore work.

This process is straightforward, adds Pavia: “We go into the reservoir, analyse

Right: Glori scientists validate custom nutrient set-ups to activate key microbes and mobilize oil

the oil and the water and the microbes, take them into the lab and design a custom set-up of nutrients that allows them to become active again.”

Senior vice president of operations, Ken Nimitz, outlines how Glori works with each client to determine an MEOR strategy. Fields are first assessed for suitability: “Based on various criteria – reservoir primers if you will – things like permeability, API gravity of the produced oil, etc.” Optimal reservoir conditions for AERO deployment are typically a permeability of around 75mD or more and temperatures below 222°F (100°C).

NEWSBASE

The next step is for a Glori technician to visit the site, taking samples to assess the reservoir bacteria and their environment.

“There are a lot of companies that take samples for chemistry, geo-chemistry, things of that nature,” Nimitz says, “But very few take samples for biology.”

These samples are then analysed in the company’s Houston lab, typically for a few weeks, where fluid chemistry screening and nutrient analysis is performed to identify the nutrient mix that will foster the bacteria, evaluating their compatibility with oil as a carbon food source and their behaviour as a surfactant.

At this point, Glori can make a recommendation. Once a nutrient package is designed, it conducts “a minimum 12-month pilot project to demonstrate the increased production and enhanced recovery,” Nimitz continues. “At which point we’ll demonstrate an uplift and we’ll be able to evaluate the new decline rate.”

The system is constantly monitored in real-time via remote systems at the injector wellheads, meaning the company can ensure the right nutrients are being fed at the right rate.

Across the board, the results are promising. “We typically see an uplift of 40 – 60% in production and then a reduction in the established decline rate of approximately 50%,” says Nimitz.

Neither is this is a “wait and see” technology – Pavia cites a far greater effectiveness compared with past “huff and puff,” shut-in MEOR techniques. Glori

InnovOil

page 44

Annual 2015

THE BEST OF 2015 A finger of microbial biofilm growing on AERO nutrients and disrupting the oil-water interfacial tension

business development director, Natalie Kiser, adds that operators can “see uplift of up to 60%, in as little as 6-8 weeks.”

The upshot is that AERO can provide a rapid turnaround in reservoir production.

The whole consultation process, from initial study to the injection of nutrients, typically takes around six months.

Proven in the field Glori has no shortage of experience in deploying the technology. Having worked to develop it with Statoil in its onshore fields since 2009 – Pavia talks of “a wonderful collaboration” – Statoil’s version of the technology is currently being evaluated in its Norne field, the results of which have shown considerable promise.

AERO’s track record extends to dozens of deployments, spanning multiple continents and working with everyone from E&P independents to national oil companies (NOCs) and “everyone in between.” A project with Brazilian national operator Petrobras is underway after studying a number of great candidates from their extensive portfolio, while a major 2013 project in Alberta has enabled exceptional life extension – the customer is estimating “At least half a decade, probably longer,” says VP sales & marketing, Daan Veeningen – not to mention a number of successful projects onshore US where Glori has been an operator. Its confidence in the technology extends to a dedicated acquisition unit, which buys into maturing and declining fields with the purpose of turning production and asset life around. This Veenigen says, is Glori “putting our money where our mouth is.”

These results are repeatable, Veeningen continues: “The reduction in decline rate [as a result of AERO] is typically 50%. [while] the improvement in production rate is somewhere between 50 and 70%. These economics are really appealing for our customers.” Such a dramatic life extension together with improvements in oil cut is also good news to anyone interested in deferring plug and abandonment costs for a vital few years for offshore platforms.

In the case of the Alberta project – a field which previous production decline

of 34% – the latest available data shows production has risen to 63 barrels per day after 18 months of injection, over four times the pre-AERO predicted rate of 15 bpd. In fact, Nimitz enthuses, “I think we’ve yet to define the new decline rate because production continues to increase, and that’s been a little over two years.”

It should also interest those with their eye on the bottom line. AERO is provided as a monthly service, but “the best [cost] metric is per incremental barrel, and we aim for a cost of no more than US$10 per barrel,” says Nimitz. Because of its highly competitive CAPEX and OPEX costs – in the hundreds of thousands of dollars or NEWSBASE

less – the system can be used on small reservoirs producing less than 100 bpd.

“There are a lot of people that are aware of [MEOR’s] history and are sceptical about microbial approach, but we have some phenomenal field results now,” says Pavia. Glori believes it has the technology today which can change the fortunes of hundreds of maturing fields across the world. And seeing their results, we’d be inclined to agree. n Contact: Daan Veeningen

Tel: +1 713 237 8880 Email: sales@glorienergy.com Web: www.glorienergy.com

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

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

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immediate interest that our article attracted.”

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