Innovoil Issue 38 October 2015

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™

NEWSBASE

Bringing you the latest innovations in exploration, production and refining Issue 38

October 2015

Power.

Deeper.

An in-depth look at Nautilus subsea connectors Page 10

CTRL + PRNT

How 3-D printing could change oil and gas Page 6

DO MORE FOR LESS

Our supplement tackles production efficiency innovations Pages 9-25

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InnovOil

October 2015

page 3

Inside 5

Control + Print

6

Could the oil and gas industry embrace the potential of 3-D printing?

Contacts:

Production efficiency 9

Media Director Ryan Stevenson ryans@newsbase.com

10

Breakthroughs

12

Well-trained

14

More sand, less time

15

Full steam ahead

16

Obsolescence risk

18

Clariant’s innovation philosophy and how this adds value to customer operations

Media Sales Manager Riley Samuda RileyS@InnovOil.co.uk

AGR’s integrated approach to production efficiency

Editor Andrew Dykes andrewd@newsbase.com

Desanding from Stork

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

Bronswerk Heat Transfer explores mechanical vapour recompression (MVR) using Radiax® technology

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

Through Life Support (TLS) offers its perspective

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

Temperature monitoring 19 LumaSense Technologies® help to keep assets efficient and safe

Low-NOx emissions

21

Suite solutions

22

The week ahead

27

Not so tough at the top

28

News in Brief

32

ClearSign’s Duplex™ technology has the potential to reduce emissions

™ NEWSBASE

ations Bringing you the latest innov

Power to producers

How Teledyne’s subsea interconnect systems are enabling new deepwater developments

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

Published by

A note from the Editor

and refining in exploration, production

Month 2015

Issue XX

Honeywell Process Solutions’ on the future of the digital oilfield

POWER. DEEPER.

An in-depth look at Nautilus subsea connectors Page 6

Interview with Maria Moraeus Hanssen

The largest firms are finding it easier to weather the storm fall in crude prices

CTRL + PRNT g could How 3-D printin change oil and gas Page 8

CLEAN AND EFFICIENT

Our supplement tackles production efficiency innovations

Contacts 38

Pages 11-25

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InnovOil

page 5

A note from the Editor With the crowds dispersed and the City of Aberdeen returned to a relative calm – or at least business as usual – we can begin to take stock in the aftermath of SPE’s Offshore Europe.

While some suggested that a little of the extravagance was gone, rumours of the industry’s demise have been greatly exaggerated. Reported attendance was the event’s second highest ever, just under 56,000 visitors over 4 days.

Despite the substantial amount of technology to survey, I managed to catch the opening plenary session, where the panel of speakers did not shy away from some of the major issues facing the sector. In particular, keynote speaker Professor Brian Cox tackled some of the challenges and solutions connected to the central theme of “How To Inspire The Next Generation.”

His main message was that in order to encourage students towards the energy industry, it must provide “information as well as inspiration.” Young people must be able to see an academic and career path, and to see science and technology at work, in order to secure their interest in the field.

Given his stellar knowledge, Professor Cox also dealt with some novel ideas – calculating the energy output of a star’s supernova in British thermal units, and drawing attention to the lakes of liquid methane on Titan, Saturn’s largest moons, to list but a few. The outcome was to place the energy industry firmly within a universal perspective, as well as a global one.

On the exhibition floor, there was no

shortage of innovation, but this year brought an almost exclusive focus on technologies which could bring cost, time and efficiency savings – and this month, our supplement on production efficiency does so too.

It is a broad topic, and we have input and features from a number of different fields, including chemicals, software, services, training and more.

As well as in-depth interviews around Honeywell Process Solutions’ and Clariant Oil Services’ approach to innovation, we feature a range of efficiencyboosting ideas and technologies from ClearSign’s cleaner NOx burners, to new AGR training courses specifically designed for a low-price environment. Also contributing to the edition are Stork, Through Life Support and LumaSense, while Bronswerk explores new and innovative applications for its Radiax compressor.

Our edition sponsor Teledyne Oil & Gas also details the engineering and design process behind its newest subsea interconnectors, capable of working in some of the toughest deepwater environments.

Next month, we turn our attention to technology which can help unconventional producers – if you have a product or technology which the wider world should know about, let us know. For now though, the team and I are pleased to bring you the October edition of InnovOil. (And for those interested, Cox reckons that a dying star would produce roughly 1042 Btu.)

Andrew Dykes Editor

NEWSBASE

page 6

InnovOil

October 2015

Control + Print COMMENTARY

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

October 2015

InnovOil

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COMMENTARY 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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October 2015

InnovOil

Production efficiency

page 9

Special supplement Pages 9-25

Sands on time Advanced Online Desanding from Stork Page 15

Train on TRACS

AGR’s integrated TRACS Training Page 14

Great first compressions

Suite things

Honeywell Process Solutions looks at the future of software

New applications for Bronswerk’s Radiax compressor

Page 22

Page 16

NEWSBASE

page 10

InnovOil

October 2015

Power to producers Production efficiency

After a successful Offshore Europe, InnovOil caught up with John Flynn of Teledyne Oil & Gas to talk about how the firm’s subsea interconnect systems are enabling new deepwater developments

A

lthough some of the most commonly used options for maintaining and enhancing oil recovery, the technology behind subsea boosting, pumping and processing still requires constant innovation. Done right, these systems can significantly enhance production with comparatively minimal CAPEX and OPEX. They are a valuable part of most enhanced oil recovery (EOR) operations, whether to help return hydrocarbons to topsides facilities or to inject water and/or additives into the reservoir.

As operators go deeper and more processes are moved to the sea floor, such equipment is becoming more and more necessary. The same efficiencies and advances made over the past few years mean that previously uneconomic marginal or brownfield sites may now be rejuvenated with new subsea facilities and tiebacks. Similarly using robust, modular systems ensure that OPEX is controlled and reduced. Reliable equipment is unlikely to fail, and maintenance intervals can be lengthened; when equipment does need repair or replacement it can also be done without major interruption to production.

Much of this equipment is now enabled to include monitoring and data-capture, meaning issues can be identified in real time, and operators can better plan their approach to asset integrity, flow assurance and maintenance.

Spanning all these trends, pressure on cost and on project timelines mean that operators are demanding that these projects are less expensive and more efficient. Recent years have seen a major push for greater standardisation, especially within the subsea sector, where a myriad of connectors, cables and pumps could be streamlined into far more cost-effective systems.

Better connected Even with technological advances, actually powering subsea equipment remains a

major challenge. Teledyne Oil & Gas (TOG) understands this, having worked closely with the system integrators to power new and existing fields in extremely harsh deepwater conditions. The group provides reliable electrical interconnect to power subsea pumping and boosting equipment, as well as unique monitoring solutions as part of its Cormon line.

Its expertise in the former include electrical and fiber optic wet mate connectors, power connectors from 6kV to 15kV, electrical penetrators, and umbilical termination assemblies. It has also developed a number of new and custom products for bespoke projects, thanks to the work and expertise at its Daytona Beach Technology Development Center.

The Cormon range includes sensing and monitoring systems to detect corrosion and erosion rates via metal loss measurement. Cormon also offers sensors to measure pressure and temperature, either standalone, or integrated into corrosion and erosion probes. All of these help to enable better production efficiency by giving users access to real-time information and enabling them to make better decisions about when they should intervene.

In this way, TOG focuses on minimising the life cost of the product, and not just the upfront cost.

NEWSBASE

The Nautilus™ One of the major components of TOG’s subsea fleet is the Nautilus™ wet mate connector. The patented design was first developed in 1991 by an ocean scientist, and now over 110,000 connectors are in use across the oil and gas, ocean science, and defense sectors. Configurations include ROV, manual and stab, with ratings up to 250 Amps.

With a patented shuttle pin design, it offers exceptionally reliable multichannel electrical connections. For added redundancy, it features dual independent seals and oil reservoirs; the pin enters these reservoirs before sealing via the shuttle pin and dual wiper seal assembly, simultaneously cleaning and sealing the pin and providing two completely separate barriers.

Most recently, TOG engineered a new line of 60-A Nautilus wet mate connectors for use in the North Sea. These are capable of handling more power than standard 30amp models, and will be used to power the magnetic bearings in the new subsea gas compressors.

VP of global marketing communication for Teledyne Marine, John Flynn, comments that: “The major project challenges here were developing and qualifying new high temperature pins and bladders capable of operating above

October 2015

InnovOil

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Production efficiency

Ceramic Penetrator Pin

4-pin Nautilus connector

traditional Nautilus internal temperatures of 50°C.” To achieve this requirement, the team adapted its standard Nautilus design by qualifying new higher temperature materials for bladders and boot seals.

The result is a connector that operates at pressures of up to 4,350 psi in 10,000 feet of water. In the long term, this added engineering ensures the connectors are reliable and robust when in use subsea.

Space-age ceramics As has been noted, subsea developments are moving deeper and with longer tiebacks. Royal Dutch Shell’s Appomattox development in the Gulf of Mexico, approved in July of this year, for example, has a substantial subsea template in 7,200 feet of water. Big challenges are posed in terms of supplying power to this kind of infrastructure Electrical penetrators are used in subsea systems to power boosting or submersible pumps at the seabed. The penetrator is exposed to high differential pressure, harsh pump fluids, temperatures of up between 35°F-250°F (1.6°C-121°C), and uninterrupted voltage of 10 kV during operation.

“The industry traditionally uses thermoplastic materials in penetrator designs. When dealing with high pressures

and high temperatures, thermoplastics may not provide the required reliability,” Flynn says. Field operators at another Gulf of Mexico project approached TOG to research and design a penetrator system for horizontal ESP-seafloor pumping.

This had to be capable of handling 250 A of current, and pressures up to 12,880 psi (inboard-to-seawater), meaning new materials would have to be used.

To devise a suitable penetrator, TOG assembled a cross-disciplinary team from both Teledyne ODI and Teledyne Scientific and Imaging (TS&I) to develop a design using ceramics, and incorporate a new copper conductor pin. “The team included representatives from mechanical engineering, moulding, reliability engineers, process engineers, and materials scientists,” Flynn explains. “We worked very closely with Teledyne Scientific, our research partner in Thousand Oaks, CA, to develop the ceramic components. The scientists have a history in helping design ceramic tiles for the space shuttle, among other components in the space program,” he adds.

The operating environments of space and deep sea have their similarities, he points out – “challenging environments, extreme temperatures, differential pressures, lack of access for repairs, expensive maintenance,” he says – and the NEWSBASE

team’s experience with materials was a major asset in choosing the right ceramics for the task.

In the final design, “The new penetrator pin enabled the penetrator to handle the thermal expansion of the copper conductor while the ceramic material withstands the extreme pressure.”

Custom boot seals were also designed and qualified to withstand the harsh pump fluids, and to provide the necessary electrical stress control for the high voltage electromagnetic fields.

Success with its 10 kV model has now led TOG to develop another, 15 kV model for deepwater work offshore Brazil.

“Every oil field has different operating conditions, and every customer has different interface requirements or specifications,” Flynn says. “But our strength is really to develop core technology, such as a ceramic penetrator, or reliable wet mate connector technology, and adapt it to our customer’s needs and to fit their specific applications.” Harnessing the expertise and resources of its talented team, there are few limits to the range of Teledyne Oil and Gas innovation. n Contact: John Flynn

Tel: +1 386 236 0780 Email: john.flynn@teledyne.com Web: www.teledyneoilandgas.com

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InnovOil

October 2015

Production efficiency

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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Production efficiency

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

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InnovOil

October 2015

Production efficiency

Well-trained with AGR

AGR’s Rita-Michel Greiss and Roger McIlroy sat down with InnovOil to discuss the company’s integrated approach to production efficiency – and how that knowledge can be passed on

C

ommunication and collaboration are often perceived as overused buzzwords within the industry. Yet these actions have never been more necessary than right now.

As AGR production technologist Roger McIlroy acknowledges: “These are very hackneyed phrases these days but it’s true!”

The company is known for its subsurface, well and field optimisation engineering expertise – skills which are increasingly being used by operators looking to maximise production from their existing assets. The approach, as McIlroy explains it, is informed by four main principles: examining existing well stock, improving sweep optimisation in the reservoir, optimising well delivery and investigating potential near-field assets.

In terms of the former, he adds: “The AGR view is that all mature wells will have at least one opportunity to increase productivity, and often these opportunities are at low cost or at no cost at all.” This new “injection of life,” as BD manager for AGR’s Reservoir Management UK unit, Rita-Michel Greiss adds, can be as simple as adjusting or replacing a choke valve on an older well, or redistributing gas between wells as part of gas lift optimisation.

Key to its work in sweep optimisation is “locating the remaining oil,” or LTRO. This, Greiss adds, is “very much an integrated subsurface activity... We look at geological features as well as seismic, and look at reservoir engineering sweep calculations and core tests to decide how best to locate and recover the remaining oil, which, by the way, can often be as much as 70% of the initial oil in place (OIP).”

Involving teams from across the spectrum, these processes link “reservoir engineers with production technologists… as well as geophysicists, production geologists and petrophysicists”.

Communication, collaboration and shared models are very much at the heart of the firm’s holistic approach, and extend right through to optimising well delivery via smart procurement and drilling, and to

Rita-Michel Greiss and Roger McIlroy near-field developments enabled by the latest technology and tieback facilities.

Making TRACS Where AGR distinguishes itself is in passing this knowledge on. “Many of our engineers are working on an operator’s problems one day, and teaching the solutions the next,” says McIlroy. AGR’s TRACS Training courses cover graduate, masterclass, openair and technical programmes, a “training portfolio which goes across the reservoir and into wells – so we teach everything we consult on,” he continues.

As well as teaching new students and professionals, this also keeps AGR personnel aware of the latest developments in technology and operator strategy.

“Client feedback for us is incredibly crucial,” agrees Greiss. “There are always new developments – it’s not until an operator uses a technology that you understand how it performs for a client – that is the kind of expertise you can only develop with time.”

Teaching methods are more involving, using the real case studies and interactive tools at the company’s disposal to ensure not only engagement, but also that young professionals are ready for the workplace once they arrive. “We offer a type of training called experiential training,” explains McIlroy. “It’s not just someone NEWSBASE

standing up lecturing at you for 6 hours a day; it has to involve actual pieces of downhole equipment, videos and multimedia to show how tools work and how reservoirs operate.” This culminates in dedicated exercises, using real data to solve actual technical challenges.

Such courses are extended to mature engineers working in mature assets, with a number under development for existing staff who need to be updated with the latest tools and technologies. McIlroy is currently working on a new course with sections dedicated to production optimisation, and titled “Maximising oil productivity in a low price world.” AGR believes that such training – incorporating LTRO, optimisation modules and more – is an excellent way to improve results from existing assets in the short term.

The overarching theme is that focus on integration, collaboration and knowledge transfer is key to extracting more from existing assets, as “operators only forced to work harder with reduced staff and cash flow means that bridging the gaps between industry disciplines will only become more important,” Greiss says. n Contact: Rita-Michel Greiss,

BD Manager Reservoir Management UK Tel: +44 (0)1224 629 000 Email: rm-uk@agr.com Web: www.agr.com

October 2015

More sand, less time

InnovOil

page 15

Production efficiency The filtration unit within the modular AOD system

Advanced Online Desanding from Stork is now in its third generation – and still helping to keep separators clean and efficient without extended downtime

S

and removal and cleaning offshore is never an easy task.

Often it involves shutting down large production systems for weeks, interrupting output and requiring multiple specialist crews. The cleaning and removal of contaminated sand and salt from production separators is particularly time-consuming, and involves exposing personnel to various naturally occurring radioactive materials (NORM) and a lot of manual work in very confined spaces.

Even once the sand is removed, it poses a problem in terms of decontamination and safe disposal. Under environmental regulations, it must be reduced to under 1% oil on sand if it is to be disposed of overboard. In the past, lack of alternative solutions has meant operators transporting waste solids back to shore for treatment and disposal, at unnecessary cost.

With production efficiency increasingly at the forefront of operator’s minds, preventative cleaning and maintenance has often proved to be a wiser strategy than reactive solutions. Several years ago, Stork devised equipment and techniques for what it terms Advanced Online Desanding (AOD) for live production separators. A success with operators, it has subsequently undergone several improvements and is now in its third generation.

AOD The deployment process begins with inspections undertaken by Stork’s specialist five-person team. The separator is examined using a thermographic camera to determine

the location and extent of the sand inside.

The remainder of the process is carried out with various pieces of modular equipment. A jetting unit injects highpressure water into the vessel to dislodge and fluidise the sand inside. The resulting slurry then passes into a solids-separation package, where it is coarse-filtered and the pressure is reduced.

A spin filter and hydrocyclone filter catch both larger and minute particles of sand before passing them into the sandwash tank. Here it is cleaned with a solvent, and reduced to oil content of 1% or below – safe to be disposed of overboard, and without the need to be transported back to shore. Indeed, recent tests by one operator consistently average under 0.5%.

After filtering, the water is passed into a recovered liquid tank where it is separated through gravity and over time. This also allows AOD particle separation to be variable and precise – removing particles from 10 to 500 microns. The final clean water is then re-injected into the separator to be reused free of chemical issues like corrosion.

This process allows 20 tonnes of sand to be removed per day without sand washing, and up to 10 tonnes per day with sand washing – a typical operation subject to process conditions can be completed in 7 NEWSBASE

days. While desanding systems are not new in themselves, AOD offers even greater flexibility for offshore operators. “While 40 bar is the maximum design pressure for most 3 phase separators in the North Sea, in some other regions in the world, this could be as high as 60 bar. Stork considered it wise to make contingency for this scenario,” Stork desanding technical authority Stanley Okosodo explained to InnovOil. Weighing around 23 tonnes in total (dry), and with a footprint of 30 square metres, the stackable ATEX-2 certified kit takes up minimal deck space and can be deployed without major disruption.

This rest of the year will see Stork look to bring AOD to new regions, in particular to operators in South America and Southeast Asia, Okosodo says. Meanwhile, the latest (fourth) generation of the system is already in the works, with plans to reduce the system’s footprint even further and to enable working at pressures of up to 100 bar. All of which sounds more than enough to keep Stork’s team busy into 2016. n Contact: Stanley Okosodo, Technical Authority – Advanced Online Desanding Tel: +44 (0)1224 722 888 Email: Stanley.Okosodo@stork.com Web: www.stork.com/aod

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October 2015

Production efficiency

Full steam ahead with Radiax

®

Bronswerk Heat Transfer explores the potential of mechanical vapour recompression (MVR) using Radiax® technology

S

team systems are a part of almost every major industrial process today. For various heating processes, steam is used as a heat carrier for evaporating solvents in distillation columns, drying and reactor columns. Roughly a quarter of the oil and gas consumed in the process industry is used to generate steam.

As one of the largest sources of energy demand, and given the frequency of outdated plant arrangements, improvements can lead to significant energy and cost savings. As more companies also look to reduce emissions and improve efficiency, steam production processes are a frequent target.

Mechanical vapour recompression (MVR) is one solution. The process works by recycling unused low-value steam, mechanically converting it to high-value steam while preserving its latent energy.

It can reach coefficient of performance (COP) values of up to 10, and when used in conjunction with Bronswerk Heat Transfer’s advanced Radiax® compressor can offer even greater advantages.

The Principle of MVR During MVR, a mechanically driven compressor increases the pressure of a steam flow. The compressor operates as a heat pump by adding energy to the water vapour.

But contrary to the compression heat pump, which uses separate circulating fluid (a closed system), MVR works as an open system.

In an open heat pump system the process fluid – in this case steam – also acts as the circulating fluid. With the elimination of the evaporator, condenser and separate circulating fluid, the system can maintain

Figure 1: A log(p)-h diagram of water

Figure 2: Cross-section of the Radiax compressor

Input

Rotor Stator diffusor Electric motor Shaft Plate heat exchanger

Output

high COPs of up to 10.

In Europe, steam prices can be between 20-35 euros (US$22-39) per tonne. With thousands of tonnes being used per hour, savings made here can be considerable.

Bronswerk business developer Geert ten Brink notes that the technology is gaining traction, primarily because “declining electricity prices in Western Europe in contrary to gas prices making MVR more favourable, even though the technology has been around for 15 years or so.”

An example MVR cycle is illustrated in the log(p)-h diagram of water (Figure 1) where flashed vapour is upgraded from 2 bar(a) to 4 bar(a) of superheated steam in a single-stage Radiax® compressor.

The mechanical work delivered by the compressor is depicted as dH. Steam leaving NEWSBASE

the compressors is slightly superheated as a result of the dissipated thermal and mechanical losses of the compressor.

Additionally, the superheated steam can be tempered or de-superheated to its saturation point by injecting boiler feed water (BFW) in order to attain the required process conditions.

Radiax® Different types of compressors such as centrifugal fans, turbo-compressors and rotary root blowers are suitable as mechanical vapour compressors, if operating according to the principle of continuous flow machines. But each compressor type has its limitations on pressure ratio, volume flow and operating flexibility.

Bronswerk Heat Transfer has developed

InnovOil

October 2015

page 17

Production efficiency Figure 3: An MVR configuration using Radiax

Vapour leaving the rotor enters the stator-diffusor, where dynamic pressure is converted into static pressure. Vapour enters the stator-diffusor tangential and is guided by 3-D channels which ensure a perfect transition in axial direction. The rotor, electric motor and stator-diffusor are all integrated in a single casing, minimising the amount of components and producing a far more compact design.

The Radiax® offers highly variable inputs in terms of pressure and flow, meaning maximum flexibility without compromising on overall efficiency.

It is also around 60% smaller in size and weight compared to conventional MVR compressors, saving on transport, deployment and plot space.

It also features a high pressure ratio of up to 2.0 per stage for steam, with a maximum of two stages per compressor.

It is capable of handling two-phase fluids, enabling boiler feed water (BFW) injection upstream to temper the temperature of the compressed superheated steam.

This ability to offer a range of pressure change, rather than a fixed step, also means users can adjust compression according to the anticipated demand for steam, again building greater overall efficiencies and potential cost savings. Because of the integrated electromotor, the compressor is free of oil and oil seals, meaning there is no risk of leakages which could contaminate the steam. a new compressor which eliminates various limitations known from conventional systems. Based on new work in fluid dynamics, the unit is a compressor with an operating range rather than a single operating point. The unit provides continuously variable speed, flow and pressure, from a very compact size, many times lighter and smaller than conventional machinery.

Figure 2 illustrates a cross section of the Radiax®. The specially designed inlet rotor – directly driven by an electric motor – provides no-stall characteristics, meaning a smooth axial pressure rise. The divergent rotor design also contains a large number of blades reaching tip speeds close to the speed of sound, while converting flow speed in dynamic pressure.

Steam savings One recent case study used a Radiax® compressor as part of the MVR process.

In this project, a chemical plant derived its product from a reactor column that requires 7,000 kg/hr of steam at 4 bar. Steam is sourced from a steam boiler and directly injected in the reactor column, to produce 300,000 kg/hr of condensate.

For this case, energy prices are 25 euros (US$28) per tonne of steam and 0.06 euros (US$0.067) per kWh for electricity.

Assuming that the plant runs for 8,600 hours per year, total energy expenses are 1.505 million euros (US$1.68 million) per year.

This system can be easily optimised by adding a flash tank and a thermal vapour NEWSBASE

recompression (TVR) unit. By relaxing the pressure of the 300,000 kg/h of condensate from 4 to 3.4 bar, 4,500 kg/hr of condensate is flashed. This low-pressure steam will be upgraded by a steam ejector (acting as a thermal heat pump in this situation) which only requires 2,500 kg/hr of high-pressure steam to drive. This configuration reduces the expenses on energy to 537,500 euros (US$600,000) per year.

Applying MVR using Radiax® technology can cut energy expenses further, to only 103,200 euros (US$115,000) per year. In this scenario, the pressure of the 300,000 kg/hr condensate is relaxed to 2.85 bar, flashing 7,000 kg/hr of condensate to low-pressure steam. Steam derived from the flash tank is compressed in a single compression stage to 4 bar, absorbing less than 200 kW of electric energy.

The MVR configuration using a Radiax® compressor is illustrated in figure 3. This relatively simple modification can save around 1.4 million euros (US$1.5 million) on energy compared to the conventional system.

The study demonstrates that MVR using Radiax® technology is a simple and effective solution for reducing both a plant’s energy usage and its carbon footprint.

With maximised flexibility and minimised complexity, the unit is suitable for use in a wide range of applications, from factory processes to oil and gas production, transport and storage.

Additionally, only minor modifications are required to fit the Radiax®, using only a small area of the available plot space.

The savings offered also mean that initial capex of the compressor is returned within 2 years.

Building on the success of the Radiax®, Brink says that the company is actively “looking for more cases in which to participate,” and with new Radiax® compressors now in development, 2016 is set to be an exciting and busy year.

“More and more industries are now getting interested in MVR,” he concludes.

“There are still a lot of processes that can be optimised and places where users can significantly reduce their costs.” n Contact: Geert ten Brink Tel: +31 (0)33 24 72 521 Email: geert@bronswerk.com Web: www.bronswerk.com

InnovOil

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October 2015

Production efficiency

Reducing obsolescence risk with TLS Through Life Support (TLS) offers its perspective on obsolescence £ management, and how careful planning can make a major difference to long-term operating Existing costs and efficiency Stock

Reclamation Alternate

L

Equivalent Aftermarket Emulation (Subsitute)

ife extension, although a preferable (TLS) with fellow director David Williams. choice for many operators in the TLS’s aim is to support all the policy, plans, current environment, is nonetheless processes, tools and contractual guidance a difficult business. Although using operators need to tackle OM effectively. and maintaining current equipment It also provides one-day awareness and is often cheaper than replacement, three-day intensive courses and training additional problems can arise if programmes for those looking to components fail or modifications need understand the issues. to be made. If these parts are no longer available from a manufacturer or other Subsea JIP sources, re-design (or full replacement Although both directors’ backgrounds with new equipment) may be the only are in aerospace and defence, Kelly and option, at even greater costs and with loss Williams have been instrumental in recent of production. Life extension OM work for oil and gas then begins to resemble a majors. A 2011 JIP involving false economy.

BP, Statoil, Total, Chevron, A slew of recent work in Inpex and Woodside enlisted the North and Norwegian TLS as part of their efforts Seas – EnQuest’s Thistle to establish an OM strategy Alpha, Statoil’s Oseberg C, for subsea equipment. Its BP’s Magnus – illustrates the primary role was to develop extent to which operators are a Recommended Practice facing up to these issues.

(RP) document which would Obsolescence management provide a uniform process for Stuart Kelly (OM) seeks to mitigate these managing obsolescence risk, potential issues. Identifying to “help both operators and risk at an early stage – and managing the supply chain to understand what was it – means that operators can plan and required, and do it in a uniform way,” Kelly anticipate the effects of obsolescence, says. without costly intervention later in the “We spent a lot of time with the life cycle. Done properly, proactive OM operators understanding their requirements involves operators, manufacturers and and their challenges,” he continues. This the wider supply chain to ensure that also involved reaching out to suppliers obsolescence is managed as an integral part directly to gain their perspective, and to of design, development, production and see what measures could be put in place to in-service support. As a result, the financial encourage proactive OM. impact of loss of production or failure can The RP document was published in be minimised.

2014, and marks an important beachhead Demand for OM expertise led Stuart in OM strategy for the oil and gas industry Kelly to set up Through Life Support – not least, Kelly points out, because it saw NEWSBASE

Minor Redesign

Major Redesign

6 firms come together to collaborate on an important standard. The changing nature of the sector and its equipment also means that the scope of OM work has also grown, while shifts in environmental or working policy – e.g. RoHS, RoHS2, WEEE and REACH – can have similar results.

“Proactive OM traditionally looked at high-risk electronics, however, although this is still a significant risk, the discipline now regularly includes the management of non-electronic parts which can also pose an obsolescence risk to equipment,” Kelly continues. Neither is it limited to the subsea sector: “These issues are the same across many sectors, it’s just the equipment (and the potential resolutions) that differs… These processes are applicable to equipment for subsea, topsides, test equipment and more.”

All in all, there is likely to be a significant growth in demand and specifications for OM in the hydrocarbons industry, and Kelly is positive that TLS will play an important role for companies beginning to tackle it. “It’s at an embryonic stage in oil and gas at the moment, but it can only go one way – and TLS wants to be there to help implement these OM plans.

If the major operators are contracting for OM now as they are, the supply chain will start to take notice.” n TLS’ next OM course runs October 20-22 in Bristol.

Contact: Stuart Kelly

Tel: +44 (0)782 505 3292 Email: stuart.kelly@throughlifesupport.com Web: www.throughlifesupport.com

October 2015

InnovOil

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Production efficiency

Making sense of temperature monitoring

LumaSense Technologies® explains how its range of temperature monitoring equipment can help to keep assets efficient and safe

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umaSense Technologies® designs and manufactures a range of products and systems to monitor critical temperature applications, of particular use to the upstream and refining sectors of the oil and gas industry.

Its equipment, from single-spot infrared radiation pyrometers to thermal vision and imaging systems, can be used to monitor processes accurately and provide reliable temperature readings throughout production infrastructure.

For gas detection and analysis, LumaSense also produces analysers, monitors, and detectors which use the latest photoacoustic spectrometry (PAS) and nondispersive infrared (NDIR) technology.

SRU-ready The optimal operation of sulphur recovery units (SRUs) requires the measurement and control of a complex sequence of processes.

Of particular importance is the accurate control of the reaction furnace temperature to avoid damage to the refractory wall at high temperatures, and the prevention of ammonium salt from plugging the converters at low temperatures.

Installations that use the reaction furnace to incinerate waste gases such as ammonia and hydrocarbons must maintain an adequate temperature to assure gas destruction. Advanced processes, such as O2 enrichment, normally involve even higher temperatures and demand close monitoring.

The LumaSense E²T Pulsar family of detection systems are designed for continuous and instantaneous measurement of refractory temperature, gas temperature or integrated temperature in a given vessel.

Measurements are calculated via infrared technology, while the unit is kept away from heat, vibration and corrosive gases.

Flare stack monitoring Pilot flame detection must be monitored to assure ignition of gases during flare operation. Continuous monitoring of pilot flames and flared gases is critical to ensure

that the gases will be ignited and to confirm compliance with government-set pilot status recording requirements.

LumaSense’s E²T QUASAR family of detection systems are built for continuous monitoring of pilot flame (PM), flared gases (FM) and smoke particulate (SM) from flare stacks. The optical viewfinder and variable fields of view allow the QUASAR to be positioned up to 400 m from the flare stack.

Critical vessel monitoring Critical vessels can also be notoriously difficult to monitor, as extreme temperatures and temperature variability pose significant challenges to traditional methods. LumaSense thermal imaging cameras and LumaSpection™ systems accurately measure temperature and operate by using reliable infrared technology. These high-tech instruments can operate remotely and can precisely determine the object temperature and temperature distributions, even on small objects. These systems also have the ability to see through flames and detect weak parts before they lead to critical damage.

NEWSBASE

Dissolved gas analysis Within refineries and other sites, transformer condition assessment and failure analysis is a high priority. Electrical and thermal stresses on insulating materials – arcing, corona discharge, sparking and overheating – can result in transformer faults. The accumulation of such stresses on the insulating material results in their breakdown, and the release of different gases.

Detecting these gases via dissolved gas analysis (DGA) systems provides a sensitive and reliable way to determine the type of pending or occurring fault – so much so that DGA of transformer insulating oil is considered the single best indicator of the transformer’s overall condition.

LumaSense’s SmartDGA online diagnostic methods can therefore improve service reliability, avoid transformer failure and defer capital expenditures for new transformers. n Contact: Gerard Ames, LumaSense Technologies Tel: +31 (0)165 381 800 Email: info@lumasenseinc.com Web: www.lumasenseinc.com

Saltel Expandable Steel Patch An enhanced Oil Recovery Solution Innovative setting process with high pressure inflatable packer contrasts with traditional cone setting Saltel Industries has developed, tested and successfully trialed the use of an expandable stainless steel Patch (steel tube + outer skin with a profiled sealing system) for perforation shut-off.

Run on tubing or e-CTU, it is expanded downhole using an inflatable packer to create a high pressure inner lining inside the casing.

Applications include water and gas shut-off, modifying injection profiles, and repairing short lengths of damaged or corroded casing.

Benefits • A proven technology ( + 500 patches set worldwide since 2010 ) • 97 % Success ratio • Small run-in diameter, simple setting process • Minimum reduction in ID, Large through passage • A reactive skilled operations team available worldwide • Fast feasibility study, job evaluation and proposal • Patch availability : short lead times & fast setting www.saltel-industries.com/io1

www.saltel-industries.com/io1

October 2015

InnovOil

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Clear signs of change in low-NOx emissions Production efficiency

ClearSign’s Duplex™ technology has the potential to reduce emissions from gas burners and increase their efficiency, and could be a key investment for oil and gas producers reliant on steam generation

O

perators are frequently asked to reduce emissions as an environmental or regulatory concession, rather than as a business investment. Steve Pirnat, CEO of Seattle-based ClearSign Combustion, argues that this need not be the case.

Using ClearSign’s Duplex™ technology, Pirnat proposes: “We can not only dramatically reduce the emission produced in combustion but also improve certain operational characteristics than have inherent advantages in throughput and efficiency.”

Burners which produce low quantities of CO2, nitric oxide and nitrogen dioxide (pollutants collectively referred to as NOx) are already a market mainstay across many industries. But as regulations become even stricter, and energy efficiency becomes an even greater priority, energyintensive industries such as oil and gas will be forced to make even tougher decisions on how to tackle the problem.

Commonly, reducing emissions from burners involves either flue gas recirculation (FGR) systems or selective catalytic reduction (SCR).

The former meets some emissions requirements but can reduce the overall efficiency of the combustion process, and while the latter is more effective, it comes at a far larger cost and footprint. Pirnat believes that Duplex™ meets both issues head-on.

A new flame The Duplex system works by installing a specially designed ducted ceramic tile above a standard burner. This turns a single large gas flame into thousands of tiny, more easily controlled flames. These flames are 80% smaller and, because they work by radiant heat transfer and not convective, are he says, “fundamentally more efficient.”

The Duplex tile is positioned above the burner

One long flame is replaced with thousands of tiny, more efficient ones

Duplex technology deployed in a draft furnace NEWSBASE

Duplex was developed as part of an interesting offshoot when ClearSign was developing its Electrodynamic Combustion Control (ECC™) technology, a system which uses computer-controlled electric fields to manipulate the movement of ions and control flame shape.

Pirnat explains: “What the researchers discovered – which was somewhat shocking – is that they could achieve a dramatic reduction in emissions using the Duplex tile concept without any computer control at all.”

More efficient flames and fewer emissions with Duplex also lower the cost of operations and maintenance. With less ash deposited on boiler tubes, the equipment requires fewer shutdowns for de-coking. In turn, this can also lead to a reduction in failure rates.

The enhanced oil recovery (EOR) market in particular is dependent on once-through steam generators (OTSGs) and boilers to produce steam for oil extraction, and could stand to gain from such technology.

Analysis of Duplex operations suggest that Duplex provides a 4% saving against other potential solutions – a 3% saving on FGR and 1% saving resulting from better heat transfer.

With reducing emissions a priority for almost every industry, ClearSign is likely to be busy in the coming months and years.

In terms of future oil and gas applications, Pirnat says the firm is already looking into applications in other areas, such as gas flaring, as well as integrating Duplex directly into the work of boiler manufacturers.

But with 1,100 OTSGs in the US alone – 700 of which are in San Joaquin – Pirnat is excited about the “huge opportunity” available to both the company and operators looking to reduce NOx emissions and maximise savings. n

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InnovOil

October 2015

Suite solutions Production efficiency

InnovOil speaks to Honeywell Process Solutions’ Dan O’Brien and Michele Loseto about the future of the digital oilfield and how it is shaping production efficiency

T

hough improvements to production efficiency can be made using an incalculable amount of technologies, enhancements and engineering, an area heralded as having some of the greatest potential is in the digital space. In new ways, hardware and software are becoming integral parts of the oil and gas industry, reporting and controlling everything from supply chains to choke positions.

One firm at the forefront of the change is Honeywell Process Solutions (HPS), a unit of the US-based multinational. Citing 30 years of experience working with E&P firms, it believes its Digital Suites for Oil and Gas systems will play a vital role in the future of an increasingly digital oilfield.

In the lead-up to Offshore Europe, InnovOil sat down with the company’s global director of vertical solutions Dan O’Brien and product manager Michele Loseto to discuss its current systems, and where the sector is headed.

Suite things O’Brien works within HPS’ software division – Advanced Solutions – a unit which focuses primarily on a portfolio software along the lines of Honeywell’s core principles, he explained. Namely, its goals are “to improve safety, production efficiency, reliability of equipment and analytics.”

It is a broad remit, but solutions are geared mainly towards “improving production efficiency, process safety performance, using the innovative analytics

Xxxxx

that some of the emerging technologies like big data, mobility and industrial internet of things [IIoT] can offer.” These are incorporated into Digital Suites for Oil & Gas, the company’s flagship digital oilfield solutions for all upstream producers, from offshore conventionals to onshore unconventionals such as shale gas and coal-bed methane (CBM).

Its presence at OE15 is reflective of the number of North Sea operators already using Digital Suites. As well as its capabilities, its success is partly a result of Honeywell’s vendor and formatneutral approach. “We are absolutely open connectivity-wise to working with anybody’s process data historian, anybody’s control system technologies, anybody’s instrumentation, so we’ve got a really open connectivity platform and engine to allow us integrate with everybody’s stuff.” Such an approach is perhaps unusual for an industry accustomed to bespoke-ness, but as Loseto NEWSBASE

notes, it can help to mitigate the current industry problem of TMS – Too Many Spreadsheets.

Digital Suites incorporates multiple areas of operation, from process safety and alarm management to the visualisation and distribution of real-time production data. The latter in particular is changing how the industry thinks about the process of drilling and production. “I’ve been talking to some customers in the Permian Basin, where some of their production monitoring has as much as a day’s delay on their awareness of what’s going on in their production field,” O’Brien says.

This lag means that producers are not working as effectively or efficiently as they could be. Sourcing information on temperatures, choke positions, pressures and flow rates, as well as faster access to up-to-date well models, can dramatically improve results. “With our software, you can get that information in minutes, not in days,” he enthuses.

October 2015

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Production efficiency

Xxxxxx

Work smarter Across the board, this move towards better and more up-to-date analytics has two main drivers. First are advances in technology, especially in terms of mobile computing, devices and connectivity, and especially the evolution of the IIoT. Honeywell Pulse, O’Brien highlights, is a new “smart notification” technology premiered in the US in June 2015, and allows relevant personnel to “consume only what they need to consume, as well as a little bit of context around it, like seam trends or how events are being addressed.”

Using push notifications and locational awareness to send the right information to the right people – and at the right time – he reckons new technologies such as Pulse are “a pretty effective way to give [users] a smart indication, in context.”

Second is the improved ability of computers and operators to handle and display the information collected, via monitoring and data analytics. O’Brien

adds: “Those analytics can help a customer really identify production issues much faster, and they can then avoid things that might lead to a well shut-in, costly equipment damage or unplanned maintenance.”

Rather than storing information in a “warehouse,” to be accessed later, better algorithms, smarter processing, data federation and asset modelling allow Digital Suites to show the most important information as it is needed – in near real time. This process of federation, he continues, means that users “can leave the production information in its raw form…

This is much more reliable because it’s the data that’s kept right at the source, and that creates a better environment from a cyber security, a data redundancy, and a high-efficiency perspective.”

As InnovOil has profiled already this year in both our big data and asset integrity editions, predictive maintenance is coming on leaps and bounds as a result NEWSBASE

of such systems. The ability to know when to undertake maintenance and plan accordingly – rather than having an unnecessary or emergency shutdown – is an incredibly useful tool for boosting efficiency. Digital Suites enables operators to “use pump vibrations and things like that to help plan how to schedule maintenance,” O’Brien explains. “That’s deployed across quite a few sites in the North Sea and it’s changing the way customers build these smarter operating environments.”

Payback These smart environments are also enabling an economic overhaul. Lower prices have meant O’Brien’s division is “busier than ever,” with an increased response from operators looking for ways to manage assets effectively and efficiently in an even tougher environment.

The argument is about economics as much as it is about smarter working.

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InnovOil

October 2015

Production efficiency

“We’re able to help get more production efficiency out of the existing assets without a lot of new CAPEX,” Loseto says. “We can help them get the most of their assets, quickly identifying issues on various perspectives, and then connect everything and everybody in a holistic collaborative manner.”

Altogether, Honeywell believes it can mean a 3-5% improvement in production efficiency, equating to typical annual savings of US$5 million per year for a mid-sized field. Product manager Michele Loseto points to one case study for an unconventional producer in Asia-Pacific, where real-time predictive alerting meant savings of US$200,000 per well, per event.

In a multi-well development, this Digital Suites offered an ROI within two months.

Where next?

As the blueprint for the fully digital oilfield develops, hardware, software and

computing will be deployed in even more interesting and innovative ways. We have seen it already in the massive interest and demand for drone inspection and remote monitoring technologies onshore, and similar trends in the offshore sector with AUVs. “In the next few years the industrial software picture is going to evolve more than it’s ever evolved in the past, O’Brien says, “And it’s going to be led by the adoption of emerging technologies that have swept through things like social gaming, big data, IIoT, mobility, Cloud computing and enterprise connectivity – those are part of the big themes that we really know are going to make a huge impact in production efficiency.”

The result is: “We’re going to start relying on these devices and solutions to do things that you couldn’t do any other way.” He points to advances in software for geo-fencing and locational NEWSBASE

controls which allow drones to detect leaks and spills automatically – employing similar detection techniques to those the company has already used for quality control in the pulp and paper industry.

While large process industries can be cautious when it comes to embracing these developments in emerging technology – perhaps none more so than oil and gas – with the improvements which can be seen in terms of economics and efficiency, the case is persuasive. In most cases, the components are proven and tested – it seems it is now up to operators and providers to find even more ways in which they can be used. “Time horizons are kind of hard to predict – and I’ve been in this business a long time,” O Brien says, “But I think with the emergence of IIoT, with the adoption of mobility in industrial ways that operators haven’t thought of; we haven’t even scratched the surface yet.” n

EXPERIENCE WHERE YOU NEED IT. Milbank’s Oil and Gas Group is widely recognised as one of the premier global legal advisors to the oil, gas and petrochemical sectors. We have served as counsel in the development, financing and acquisition/ divestiture of a broad range of upstream, downstream and transportation projects around the globe (including exploration, production, pipelines and shipping, storage, refining, LNG, petrochemical facilities and production platforms, rigs, drillships and FPSOs).

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The SIM North Sea conference returns for its fourth year to unite over 200 of the world’s leading structural integrity strategists, technology The SIM North conference returns forhas its fourth innovators andSea policy makers. This event playedyear hostto tounite all ofover the 200 of the world’s leading structural integrity strategists, technology world’s top integrity experts, over a number of years, to deliver the latest innovators and policy makers. This event has played host to all of the integrity solutions forexperts, offshore fixed and floating structures. world’s top integrity over a number of years, to deliver the latest

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SIM Conference North Sea key highlights: SIM Conference NorthCOST Sea key highlights: STRATEGIES AND BEST • OPEX AND CAPEX OPTIMIZATION

PRACTICE: How to deliver cost optimization strategies to reduce OPEX for • OPEX AND CAPEX COST OPTIMIZATION STRATEGIES AND BEST asset integrity and reduce CAPEX on new projects and developments PRACTICE: How to deliver cost optimization strategies to reduce OPEX for integrity reduce CAPEX on new projects • asset SMART ASSETand INTEGRITY MANAGEMENT: Learnand newdevelopments techniques and methods for Inspection, Maintenance and Repair to reduce maintenance • SMART ASSET INTEGRITY MANAGEMENT: Learn new techniques and scopes and inspection frequencies methods for Inspection, Maintenance and Repair to reduce maintenance and inspection frequenciesSERVICE STRATEGIES: Making the • scopes LIFE EXTENSION & CONTINUED business case for life extension, demonstrating fit-for-service, and how to • LIFE EXTENSION & CONTINUED SERVICE STRATEGIES: Making the manage the effects of ageing on structures business case for life extension, demonstrating fit-for-service, and how to the effects of ageing on structures • manage STRUCTURAL DEFORMATIONS AND REMEDIATION OPTIONS: Case studies and strategies for managing corrosion, cracks, fatigue, structural • STRUCTURAL DEFORMATIONS AND REMEDIATION OPTIONS: Case damages for both fixed jacket structures and floating facilities studies and strategies for managing corrosion, cracks, fatigue, structural for both fixed jacket structures and Take floating facilities • damages TECHNOLOGY & INNOVATIONS FOR SIM: a tour of the SIM Exhibition showcasing the latest Structural Monitoring Technology, • TECHNOLOGY & INNOVATIONS FOR SIM: Take a tour of the SIM Inspection Technology, Asset Integrity and Data Management Software, Exhibition showcasing the latest Structural Monitoring Technology, Novel Repair Techniques and much more!y Inspection Technology, Asset Integrity and Data Management Software, Novel Repair Techniques and much more!y

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2015 Advisory Board: Vetted by the industry's leading SIM experts will ensure 2015's program is built by the industry, for the industry: 2015 Advisory Board: Technical Vetted byAuthority, the industry's leading SIM experts will ensure Iain Manclark, Structural BP 2015's program is built by the industry, for the industry: Terry Rhodes, Head of Offshore Structures, Shell

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October 2015

InnovOil

page 27

Interview

The week ahead

Ahead of World Oil & Gas Week, ENGIE CEO of Exploration & Production Maria Moraeus Hanssen discusses how collaboration is the best way for the industry to overcome challenges

Q A

Q

What have been ENGIE’s highlights in 2015 so far?

We had no major production milestones to hit in 2015, but it has been a good year in particular in relation to our ongoing Cygnus Project.

The main offshore installation scope is almost completed and drilling has started.

Production start will be in the first half of next year. Overall, we have had a good year for production. Even though we have been challenged on margins, the year has remained stable and we are producing according to budget.

ENGIE will work alongside Statoil, Eni Norge, Lundin Norway, OMV as part of the Barents Sea Exploration Collaboration.

How can successful partnerships and JVs enhance business performance, technology innovation and development?

This collaboration in the Barents Sea is all about safety. It is a challenging area – the weather conditions, the ice …

All of the companies working together in this region have experience of working in these conditions. When working in such remote areas, it makes sense to collaborate on things like logistic services, emergency services etc … It’s not just about cost, it’s also about creating a system that works, is efficient and safe.

A

Q

At last year’s World Oil & Gas Week, collaboration was a real buzz word.

Why do you think it is something that everyone is talking about?

The fall in commodity prices has certainly been dramatic this last year.

Over the last 5 to 20 years the oil and gas industry has managed to manoeuvre itself into unsustainable, high cost levels and those levels need to be brought down.

The oil service industry is bleeding and they might not feel like there is much

A

collaboration with the operating companies these days. But from our side as an operator in several European countries we need to be collaborating amongst ourselves – we need to create synergies within our portfolios and with other operators. In Norway, we are a single asset operator and in this instance it is especially important for us to collaborate with others.

Q A

How can operators work better with their service partners in today’s low price environment?

This is a challenging question.

Hopefully the industry can maintain continuity through these times. Today, it is very difficult to make promises. In such a disruptive environment, organisations can lose confidence and capacity. They can come out weaker, with less capacity. But it can’t be about just driving costs.

Organisations need to be careful that they don’t cut back on education and talent – they need to maintain their activity level. Exploration and production are very expensive activities, there needs to be more of a joint effort between operators and oil field services to lower costs.

Q A

Why are you participating in this panel session at World Oil & Gas Week?

I think it is important to have these opportunities to discuss important industry topics and learn from each other.

There is huge inspiration to be gained from others and key lessons on moving forwards. There is a responsibility I think for individual leaders to step up and be challenged when times are challenging. n

Specifications for ENGIE’s Cygnus Project

Maria will be joining World Oil & Gas Week in London from 16th – 18th November. www.oilandgascouncil.com/event/oilgasweek

NEWSBASE

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InnovOil

October 2015

COMMENTARY

Not so tough at the top The oilfield services industry as a whole has been hit hard by the fall in crude prices, but as Sam Wright explains, the largest firms are finding it easier to weather the storm

O

ilfield services firms’ results for the first half of the year are coming in thick and fast. With oil prices having remained low over the period, some had expected a bloodbath. Yet the signs are pointing to an industry – for those at the top at least – that is proving remarkably resilient.

During the first six months of 2015, none of the world’s largest services companies came through the collapse in crude prices unscathed. Schlumberger, the largest oilfield services firm, posted a fall in second-quarter revenue of 12% to US$9 billion. Halliburton saw profits drop from US$774 million in the second quarter of 2014 to US$54 million in the same period this year and Baker Hughes reported a loss of US$188 million in net income. But all of these companies came in ahead of analysts’ expectations, weathering the storm much better than anticipated.

“In the time that I’ve practised – the last 30 years – I’ve been through three boom and bust cycles, and many people have been around a lot longer than I have and have seen four or five,” BDO’s global head of natural resources, Charles Dewhurst, told NewsBase. “The big operators are very adept at restructuring and rebalancing when it comes to this sort of price decline. I’m pleased, to be honest, the oilfield services companies are doing a lot better than many people predicted, but it’s not entirely surprising.”

This stronger than expected performance was not only confined to the big three oilfield services firms. Among the smaller companies, Aberdeenheadquartered Wood Group posted a 13% year-on-year drop in pre-tax profits to GBP102.3 million (US$161.2 million) for the first half of 2015.

As with the industry leaders, these results were largely achieved through restructuring, with cost savings of more than US$40 million made since the start of the year. Wood Group has shed more

than 5,000 workers over the past eight months – the equivalent of 13% of its total staff. So far this year, Schlumberger has cut 20,000 jobs. Baker Hughes has lost 10,500 jobs, while Halliburton slashed around 12,800 jobs in the first half.

Speaking to NewsBase, SOLIC Capital’s managing director, Raoul Nowitz, said this level of reduction in staff was “an indicator that they see the current environment continuing for some time”. SOLIC is a capital advisory, NEWSBASE

distressed asset management and principal investing firm that specialises in energy.

Nowitz added that many firms had been investing in technology and software in a bid to be more efficient and cut waste.

“I don’t think anyone is immune. We’ve seen the small independent guys that are most exposed saying that they have to do something very significant very quickly, and then you’ve got the larger integrated firms saying that they see this as a long-

October 2015

InnovOil

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COMMENTARY The big three oilfield services firms are not doing as badly as expected

acreage uneconomic. According to some estimates, the average breakeven price among shale drillers is roughly US$50 per barrel. In some premium acreage, though, this can fall below US$10 per barrel, while, elsewhere, a breakeven price of US$80 per barrel can be expected. “On a basin-by-basin level, we see the Barnett and Bakken plays being spoken of as some of the hardest hit, and the Barnett rig count has continued to decline from 2008 levels,” said Nowitz.

“There’s a lot of gas there yet to be drilled but when prices are where they are its unlikely that we’ll see a recovery any time soon. In terms of the Bakken, there’s still a large amount of activity, and there’s an estimate that something like 40% less will be spent on services during 2015.

You see a lot of ‘mom and pop’ services operators in the Bakken simply folding up. Conversely, the Marcellus has seen sustainability and hasn’t been as badly hit.”

term structural sector shift and that they have to implement these measures immediately.”

Over-exposure Another crucial part of the services industry’s durability seems to be a broad and varied portfolio. Schlumberger, Baker Hughes and Halliburton, all of which are headquartered in Houston, Texas, count on the Middle East and Asia for their highest before-tax profit margins.

These regions have been hit less hard by the downturn than higher-cost areas such the North Sea and the US. The fall in oil prices has had a particularly dramatic impact on the latter.

Maintaining production from US shale plays requires the drilling of many more wells than in conventional fields, which translates into more work for services firms in good times. But the breakeven price for shale drillers varies massively and the downturn has made some shale NEWSBASE

More buoyant Over in the Middle East, though, the outlook seems to be far more buoyant.

While drilling in some areas has slowed, production is soaring and the need for related services remains strong. On average, onshore output has a breakeven cost of US$27 per barrel, falling to below US$10 per barrel in some instances.

“The world will continue to be heavily invested in the oil industry in the Middle East – it will have to be, because that where most of the reserves are,” Dewhurst said. “Certainly for the big three oilfield services companies – and many others, for that matter – there are tremendous opportunities in the region, and those will continue.”

Under pressure This is all well and good for the giant, well-funded services providers, but for smaller firms the future is looking distinctly more challenging. The slump

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October 2015

Commentary A technician at Wood Group PSN works in the Eagle Ford shale in South Texas, US Source: Wood Group PSN

is unlikely to pass anytime soon, with all firms regardless of their size remaining under considerable pressure.

“What we’re hearing about is that EBITDA [earnings before interest, taxes, depreciation and amortisation] is declining by around 30-35%, and liquidity profiles are being severely adversely impacted,” said Nowitz. “Our view is that this is likely to continue into the first half of 2016. We expect this to play out for some time to come.”

He added: “There’s more and more supply, lightness in demand, while China is not importing as much crude.

Companies are trying to recalibrate and regain market share but it’s going to take time for all this to happen, and there will be casualties. It’s going to at least be into 2016 we think before we see stabilisation on earnings, and then maybe a slow recovery thereafter.”

M&A potential The outlook is not wholly negative, though.

There is a consensus in the industry that mergers and acquisitions (M&A) could offer hope to many firms, with the prospect of cutting costs and boosting market share through consolidation becoming increasingly appealing.

In an interview with Bloomberg earlier this year, the head of energy investment banking at Duff & Phelps, Jim Rebello, predicted that a surge in such deals could be around the corner. This appears to be under way already with news of Schlumberger’s takeover of Cameron International.

“The service-side M&A activity will accelerate as we go through the remainder of the year,” he said. “There’s too much capacity. We don’t think every company will make it through this down cycle.”

This, it seems, could also be prompted by the closing of the deal between Halliburton and Baker Hughes, a US$34.6 billion mega-merger that was announced at the end of 2014 as prices were already falling. Once the transaction

is completed, which is anticipated by the end of the year, the combined company will begin to offload overlapping assets, leading to a spate of acquisitions by smaller players. For the market, this could well be a positive step.

“In our opinion, merger and acquisition activity will allow certain parties to weather the storm better than others,” said Nowitz, “There are clearly the benefits of scale, integration bonuses, and synergies and cost reductions.”

He added: “The more that companies fall into financial distress, the more opportunities there’ll be for stronger capitalised operators. It may not be quite here yet, but it is clearly going to be the order of the day over the next six to 12 months. With the tie-up between Halliburton and Baker Hughes – people asked if it was needed as they are such big companies. But you have significant product diversity, exposure to internal markets and economies of scale that can help enormously.”

Again, it seems that the biggest firms are the best placed to benefit.

“There are tremendous opportunities NEWSBASE

in a market like this,” said Dewhurst.

“There’s the prospect of many M&As, and we’ve already seen a tremendous number of those recently, not just on the services side, but with [international oil companies] IOCs being very active and gobbling up medium and smaller-size companies.”

He added: “Any time you have a crisis point like this there are a lot of deals, and it’s going to be the bigger diversified international players that can take the long-term view.”

Hunting for business Still, the crisis is ongoing. Recently it emerged that both Schlumberger and Halliburton had been broadening their usual contracts in a bid to win business, offering loans to crude producers to pay for drilling campaigns, or offering to take stakes in new wells instead of cash.

With banks unwilling to lend this is a sensible move, and one the industry can expect to see more of over the coming months. For the smaller players, though, it is yet another example of an area in which they cannot compete. n

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News in brief

The Polarcus Adira vessel

Seismic gains speed in West Africa A new 3-D seismic survey has begun on the Sangomar Deep, Sangomar and Rufisque permits, offshore Senegal, Australia’s FAR said in a statement on September 17. The Polarcus Adira vessel will shoot data on the north and east parts of the permits, on trend from the existing mapped prospects. The survey will cover ground where there is no existing 3-D seismic and will also provide more information around the existing SNE discovery. The acquisition should be completed in the fourth quarter of this year, FAR said, and processed products will be delivered in mid-2016.

The seismic will provide more definition on its planned appraisal work and add to the group’s inventory of exploration prospects on the shelf “where FAR sees extensions of both the Shelf Edge and Buried Hills plays”.

FAR has a 15% stake in the Senegal venture, while Cairn Energy is the operator with 40%, ConocoPhillips has 35% and Petrosen has 10%.

Gambia Work has begun offshore Senegal shortly after Polarcus finished work offshore Gambia for Erin Energy. A statement last week from the US-Nigerian company said the Polarcus Alima had recently completed the acquisition of 1,613 square km of 3-D seismic over the A2 and A5 blocks.

Processing and interpretation of the data will begin, with Erin predicting results would be

available in the second quarter of 2016. Work was carried out on time and on budget, Erin’s chief operating officer, Segun Omidele, said. Results will “allow us to build upon our understanding of the prolific plays in this emerging basin, and will assist our team in determining exploration activities on the blocks”. The blocks are on trend with the two discoveries drilled off Senegal by Cairn, Erin said.

Edited by Ed Reed edreed@newsbase.com

UWM-OG receives new jack-up rig MALAYSIA’S UMW Oil & Gas (UWMOG) has received a new jack-up drilling rig, which it says will strengthen its core drilling services and help it to expand both at home and abroad.

UWM-OG said on September 2 that UMW NAGA 8 had been built and officially delivered by Keppel FELS, a Singaporebased subsidiary of Keppel Offshore & Marine (Keppel O&M).

UMW NAGA 8 is the third KFELS B-class jack-up rig in UMW-OG’s fleet after UMW NAGA 4 and UMW NAGA 5, which were delivered to the Malaysian contractor in February 2013 and April 2014 respectively.

UMW NAGA 4 is currently working for Petronas Carigali off Malaysia, while UMW NAGA 5 is working for Korea National Oil Corp. (KNOC) off Vietnam. UMW NEWSBASE

NAGA 8 is capable of operating in around 120 metres of water and drilling to a total depth of more than 9,100 metres. The new rig is also capable of accommodating a crew of 150.

“UMW NAGA 8 is currently being prepared to be mobilised for a potential client in Southeast Asia,” UWM-OG said in a statement.

UMW-OG, which is owned by industrial conglomerate UMW Holdings, debuted on the main market of Bursa Malaysia, the local stock exchange, in November 2013.

The company has been expanding its fleet of drilling rigs and hydraulic workover units rapidly.

UMW NAGA 8 is the latest in a series of new jack-ups to be delivered to the company, with UMW NAGA 6 and UMW NAGA 7 having been handed over in September 2014 and January 2015 respectively.

UMW-OG’s second-quarter revenue tumbled 23.3% year on year to 183.4 million ringgit (US$42.3 million). Of this amount, 173.8 million ringgit (US$40.09 million) came from the drilling services segment.

Edited By Andrew Kemp andrewk@newsbase.com

Subsea UK on a mission to strengthen ties with Mexico UK subsea companies will be heading to Mexico on a trade mission which aims to

InnovOil

October 2015

page 33

News in brief

match British expertise with the requirements of the emerging oil and gas sector in Latin America’s second largest economy.

Subsea UK, in partnership with UKTI, and support by EIC, NOF Energy and Aberdeen & Grampian Chamber of Commerce, are leading the mission which will bring UK companies with experience in field performance and efficiencies, asset integrity management and deepwater subsea technology to the Mexican market.

The trade mission will expose over 25 British companies, many of them from northeast Scotland, to detailed market insights and connect them with the key players in the industry, as they look to exploit the export opportunities in one of the fastestrising oil and gas provinces in the world.

These companies will be given the opportunity to showcase their products and services to operators, potential customers and partners, and get the chance to network with government and industry officials.

Neil Gordon, chief executive of Subsea UK said: “As part of the UK Government’s strategy to help double British exports by 2020, we are seeking to promote partnerships with UK companies in Mexico. Since 2014, the Mexican Energy Reform has opened up new opportunities in Mexico for UK oil and gas companies. There are currently more than 25 British companies active in Mexico’s oil and gas sector, with many more looking at the emerging opportunities.

“Mexico’s deepwater oil projects are

crucial to the optimal recovery of the country’s reserves. UK subsea firms could play a major role in helping to maximize Mexico’s oil output, exporting the wealth of skills, innovation and experience honed in the North Sea.” “The UK is recognised as a global centre of subsea excellence in terms of skills, expertise and technology. By continuing to work closely with UKTI, Subsea UK is making sure that Mexico turns to the UK’s subsea industry to meet its deepwater challenges.”

The Energy Showcase Trade Mission to Mexico will take place from 26th September to 2nd October in Villahermosa and Ciudad Del Carmen, Mexico City.

SUBSEA UK

Petronas approves revised Ophir development plan STATE-OWNED Petronas has approved a revised final development plan (FDP) led

by Australia’s Octanex for the Ophir oilfield, located offshore Peninsular Malaysia, with first oil slated for early 2016.

xxxxxxx

The field, situated in Block PM305, is being developed under a seven-year risk service contract (RSC) originally awarded to Ophir Production in June 2014. The consortium consists of Octanex NL, Scomi Energy Services and wholly owned Petronas subsidiary Vestigo Petroleum. Octanex owns 50% of the venture, while Scomi holds 30% and Vestigo has the remaining 20%.

In a statement, Octanex said that “comprehensive project cost optimisation” work was undertaken, identifying savings of around 30% from reduced industry costs because of low oil prices. The FDP was updated to take advantage of these efficiencies, implementing a revised capital expenditure budget of US$90 million.

The Ophir RSC was originally awarded before oil prices began their steep fall from more US$100 per barrel to around US$50 at present.

Petronas had previously said RSC contracts would no longer be economically viable because the break-even point was around US$80 per barrel. That assertion brought speculation over a raft of RSC contracts that Petronas had already awarded, including the Berantai field awarded to Petrofac and SapuraKencana in January 2011 and the Tembikai-Chenang cluster awarded to Vestigo Petroleum in October 2013.

According to Malaysia’s The Star, industry executives had said Petronas would review RSC contracts once the terms were due for renewal, with many of them already in production.

According to Octanex, Ophir will be developed with three production wells, a well-head platform and a leased floating production, storage and offloading (FPSO) vessel.

Octanex’s chief operating officer, Rae Clark, said the news represented a significant milestone in Octanex’s positioning as a “future oil producer.”

“The revised project plan enhances the economic potential of the Ophir development, reflecting the reduced costs offered by the current low oil price environment,” he said.

While Ophir is Octanex’s only asset currently in development, the firm also owns two interests that are at the appraisal stage in Western Australia, in addition to stakes in seven exploration permits across Australia and New Zealand.

Edited By Andrew Kemp andrewk@newsbase.com

NEWSBASE

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InnovOil

October 2015

News in brief

Xodus enters Phase 2 of pioneering research into multiphase flow International energy consultancy Xodus Group and Dutch innovation company TNO have completed the first phase of a pioneering joint industry project (JIP) into the dynamic forces which affect the integrity of piping systems, in particular through multiphase flow.

The second phase of the project, which is expected to be run across three stages, is now open for new participants to join.

Eight companies were involved in the first phase of the project: BP, Statoil, Total, Suncor, Shell, Lundin, Aker Solutions and FMC. TNO carried out the bulk of the test work at their facilities in The Netherlands, while Xodus managed the programme and developed CFD schemes to be able to reproduce the measured results. Based on the outcome of analyses by both companies, new scaling rules were produced. Additionally, CD-adapco provided software (STARCCM+) and carried out simulations in support of the JIP. Multiphase flow, the passage of more than one fluid, gas or chemical substance through a pipeline, can cause flow induced vibration (FIV). This is an increasing concern on subsea (and topsides) production piping systems. As data is limited in this highly technical arena, the aim of the JIP is to investigate and understand the forces induced by multiphase flow on piping systems, and generate validation data for multiphase computational fluid dynamics (CFD) to model and analyse its occurrence.

Phase 1 was valued at more than £500,000 and involved testing on a 1.5 R/D stiff bend for a range of flow conditions. The inlet pipe to the bend had three configurations: straight, u-bend vertical and u-bend horizontal. Detailed measurements were made to analyse the forces acting on the bend, pressure and void fraction distributions upstream, downstream and within the bend.

Computational fluid dynamics (CFD) calculations were carried out to compare test results with a range of flow conditions.

Phase 2 is actively seeking additional sponsors and will look to extend the work carried out in Phase 1 to cover a range of

bend radii. It aims to begin in autumn this year. The scope is as follows: • Testing additional bend configurations • Preparation for testing at in service conditions for Phase 3 • Additional CFD studies The goal is to raise awareness of this complex issue and increase knowledge to incorporate into advance screening, simulation and prediction models. “This project will extend intelligence from small scale laboratory tests to ‘industrial scale’ piping systems,” said Mike Lewis, Global Lead - Computational Fluid Dynamics with Xodus Group. “As E&P activity goes ever deeper and into more extreme environments, and as subsea equipment becomes more complex, with the additional subsea processing for example, the potential NEWSBASE

increases for FIV to go unnoticed.

“The JIP is addressing this area of uncertainty in the industry and will provide a benchmark in order to carry out more accurate design calculations and prediction work. This will ultimately improve piping integrity, potentially increase production, and mitigate risk in this high consequence arena.”

“The experimental results thus far have given us new insights on how to improve the mechanical integrity analyses of subsea templates,” said Erik Nennie, Project Manager – Heat Transfer and Fluid Dynamics with TNO. “The outcome of the next phases will further improve the modelling tools for integrity analysis, as both design and operation of subsea templates can greatly benefit from these studies.”

XODUS GROUP

October 2015

InnovOil

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News in brief

Production starts from Asgard field extension Statoil has started production from the Asgard field’s Smorkbukk South Extension.

The offshore extension project is allowing for oil and gas to be produced from a reservoir that was initially considered unfeasible and could prove ground-breaking for similar mature or hard-to-access finds.

The extension’s estimated 16.5 million barrels of oil equivalent in reserves will contribute significantly to Statoil’s Asgard A FPSO. Discovered in 1985, the Asgard field was initially considered economically unviable because of its low permeability.

Smorbukk’s hydrocarbons lie in reservoirs with porosity ranging from “bricks to tiles,” according to Statoil. To access such tight reservoirs, the extension project involved the drilling of a long, multilateral, horizontal well with around 5,200 metres of reservoir exposure. This was delivered far faster and more cheaply than expected, Statoil said.

Fishbone technology was also used for the first time on the Norwegian Continental Shelf (NCS). This involved the drilling of 150 fishbones – each 10 to 12 metres long – into the reservoir from the main well.

“This is an important step forward in testing and implementing a technology that enables increased oil recovery from reservoirs where the method of fracking is not feasible,” said Mari Skaug, Petech manager at Asgard.

“The experience gained with long reservoir sections and fishbones opens up several new projects both at Asgard field and elsewhere on the NCS.” Using existing infrastructure at Asgard was a pre-condition for the extension project’s feasibility and profitability, said Statoil representative Ove Andre Pettersen, who also praised the co-operation between the parties involved.

“This has been a world class challenge.

Very few offshore fields have been developed with such low permeability under normal pressure conditions,” he said.

“The future of the [Norwegian Continental Shelf] is to a large degree dependent on cost-efficient development of small but important projects” like Smorbukk.

Statoil has a 34.57% stake in Asgard.

NEWSBASE

Partners include Petoro with 35.69%, Eni Norge with 14.82%, Total E&P Norge with 7.68% and ExxonMobil Exploration & Production Norway with 7.24%. Pending production experience, a gas injection well will be drilled to boost recovery from Smorbukk further.

Edited by Ryan Stevenson ryans@newsbase.com

SacOil begins thermal work on Lagia SacOil Holdings has begun working on phase 2 at its Lagia oilfield, onshore Egypt, the company said on September 17. Work under this phase involves the installation of steam facilities to provide thermal recovery on existing production wells, in addition to the drilling of at least five additional wells.

SacOil acquired a steam generator earlier this year and it arrived on site on September 4. Commissioning and operational testing is under way and full-scale steaming is expected to start by the end of this month.

Initially, steaming will focus on existing

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InnovOil

October 2015

News in brief

The Rosneft headquarters next to the Saint Sophia Church on the bank of the Moskva River

wells, which are only currently producing oil via cold flow. Each well will be steamed and allowed to soak for a number of days before starting output, the company said.

Work on the drilling of five additional wells, Lagia 11 to 15, will begin in midOctober. These will provide steaming work with additional drilling, it said, and provided an “ideal scenario” for the use of on-site resources and testing Lagia’s potential upside. SacOil intends to increase output at the Egyptian field to more than 1,000 barrels per day. Phase 1 of work on the field was carried out in January of this year and involved the stimulation of existing wells.

As a result of this work, production peaked at 404 bpd but the company said this has since declined owing to a lack of thermal stimulation, which will be addressed under phase 2.

The phase 2 development work is focused on the Nukhul formation’s Zone 3, one of the four reservoir units. The Nukhul contains biodegraded heavy oil, according to information from SacOil, with gravity ranging from 10 degrees API to 19 degrees API. There may be lighter reserves, of 36 degrees API in the deeper Thebes formation, but more drilling is needed to confirm this.

Gross proven and probable reserves at the field were assessed at 6.2 million barrels as of February. SacOil bought a 100% stake in the Lagia field in October 2014.

Edited by Ed Reed edreed@newsbase.com

Rosneft chief says company needs no support Igor Sechin, the head of Rosneft, has said that his company is no longer seeking government aid for major projects. “We no longer need anything,” he told reporters on the sidelines of the Eastern Economic Forum in Vladivostok on September 4.

Earlier this year, the state-owned oil operator asked the Kremlin to provide 301.5 billion rubles (US$4.48 billion) for four high-priority schemes worth a total of 1.43 trillion rubles (US$210.2 billion). The company stated it would use the funds for the establishment of the Zvezda shipbuilding and logistical complex, the modernisation of the Angarsk oil refinery and the development NEWSBASE

of the Russkoye and YurubchenoTokhomskoye oilfields, as well as gas deposits controlled by its Rospan subsidiary. Rosneft specifically asked that the government withdraw this sum from the National Welfare Fund, the country’s sovereign wealth fund.

Moscow responded to that request by saying it was willing to make 89 billion rubles (US$1.32 billion) available for the Zvezda project, which is designed to reduce the Russian oil and gas industry’s reliance on foreign equipment, but would not fund the other schemes. It also said it would not review its decision unless Rosneft could prove that the other three projects could turn a profit within five years.

In the meantime, the Kremlin appears to be looking towards other financing options.

Russian President Vladimir Putin said at an early September forum that Rosneft was now slated to receive 60 billion rubles [US$891.1 million] for the Zvezda project from its parent company Rosneftegaz. “I want to inform you that I decided to invest the resources of company Rosneftegaz amounting to 60 billion rubles into the acceleration of modernisation efforts at the Far East shipbuilding facility [known as] Zvezda,” he said.

October 2015

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News in brief

“We will develop the [Russian] shipbuilding industry for sure,” he added. “I have told you so before.”

Sechin, for his part, said that the new plan was more in line with Rosneft’s interests. “National Wealth Fund money is distributed through banks, not directly, [and] interest rates are not very profitable for the company,” he said. “This is why, like the president said, Rosneftegaz’s funds are more profitable for us. We have even agreed for a smaller sum compared to National Wealth Fund money. It is a more interesting instrument for us.”

He also asserted that Rosneft was in a position to cover its own expenses because it was generating a “normal cash flow.” The company may even be able to pay back some of its debts early this year, he claimed.

The Russian oil giant originally had asked for more than 2 trillion rubles (US$29.2 billion)) from the fund last year, shortly after it was barred from foreign capital markets in the EU and the US. It is saddled with a sizeable debt, which stood at around US$40 billion at the end of June, mostly because of heavy borrowing in 2013 to fund the acquisition of TNK-BP Edited by Joe Murphy joem@newsbase.com

CTG, CTL projects in China under fire Coal-to-gas (CTG) and coal-to-liquids (CTL) projects in China have been criticised as wasteful and environmentally problematic as a state-owned coal enterprise has begun producing oil at a US$2.58 billion conversion plant.

The plant, in the arid northern coal province of Shaanxi, is anticipated to deliver 1.1 million tonnes per year (22,090 barrels per day) of oil in its first phase stage, but already concerns are being expressed “about the economic efficiency of such industries”, the China Daily newspaper said.

Developer Shaanxi Futer Energy and Chemicals, controlled by major coal miner Yankuang Group, is aiming to raise production to 10 million tonnes per year (200,822 bpd) by the end of the second phase of development, the newspaper reported.

Shaanxi Futer’s general manager, Sun Qiwen, told China Daily that although crude prices were currently very low, the equally

low coal prices made coal-chemical projects viable.

Falling coal prices in China have pushed many big state mining companies to move into coal conversion technology, the newspaper said.

However, critics have argued that not only is coal conversion too expensive and the technology still not efficient, but that the processes consume too much water in regions already suffering from severe shortages.

“We need to be cautious while developing the coal chemical industry. It is still not that mature enough to be developed on a scale similar to petrochemicals,” Chinese Academy of Engineering analyst Jin Yong was quoted by the newspaper as telling an industrial conference at Taiyuan on September 18.

“Most coal chemical projects are located in Central and Western China, regions that face severe water shortages,” he said.

Last week there were reports of difficulties being faced by another state coal and power company, China Datang Group, in starting up a CTG plant at Fuxin in Liaoning Province.

In the same week a senior economist with China National Petroleum Corp.

(CNPC), Xu Bo, warned that China’s fragile environment could not support production of more than 60 billion cubic metres of gas per year from CTG projects.

Edited by Anna Kachkova annak@newsbase.com

SCCS Conference 2015

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InnovOil

What next …?

To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections For more information on Teledyne Oil & Gas, or its range of innovative subsea connectors, monitoring equipment and more, please contact John Flynn on +1 386 236 0780, or email john.flynn@teledyne.com If you would like to hear more about the unique and interesting applications for the Radiax compressor, and how it could make your operations more efficient, please get in touch with Geert ten Brink at Bronswerk Heat Transfer.

Call +31 (0)33 24 72 512 or email geert@bronswerk.com To learn about AGR’s TRACs Training Programmes, or the company’s integrated approach to production efficiency, contact Rita-Michel Greiss at rm-uk@agr.com or call +44 (0)1224 629 000 If you are interested in receiving more information on LumaSense Technologies’ diverse solutions for temperature monitoring, contact Gerard Ames on +31 (0)165 381 800 or email info@lumasenseinc.com If desanding operations are interrupting production on your asset, Stanley Okosodo in Stork’s Advanced Online Desanding unit may be able to help.

Call +44 (0)1224 722 888 or get in touch via email at Stanley.Okosodo@stork.com If your business is in need of a strategy or guidance for developing an obsolescence management system, look no further than Through Life Support. You can call director Stuart Kelly on +44 (0)782 505 3292 or email stuart.kelly@throughlifesupport.com For more information on Clariant Oil Services and its chemical solutions for production efficiency, contact John Schulte on +1 281 296 3244, or email john.schulte@clariant.com If Honeywell Process Solutions or its Digital Suites for Oil & Gas system could help you manage your assets, please contact Benjamin Pfeffer at WeberShandwick via BPfeffer@webershandwick.com or visit www.honeywellprocess.com For operators struggling with reducing their emissions or attempting to boost burner efficiency, ClearSign’s Duplex™ technology may be the answer.

Please contact Kaitlyn Finegan at kaitlyn@antennagroup.com To secure your pass to World Oil & Gas Week on November 16-18, visit www.oilandgascouncil.com/event/oilgasweek NEWSBASE

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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.

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