Innovoil Issue 39 November 2015

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

November 2015

Nonfriction Siemens’ magnetic oil-free steam turbine Page 20

Ocean of savings

FoundOcean discusses offshore cost-efficiency Page 9

Return of refrack A look at the companies and technologies leading the US trend Page 12

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InnovOil

November 2015

page 3

Inside A note from the Editor

5

Contacts:

Time for an oil change?

6

Media Director Ryan Stevenson ryans@newsbase.com

Gullfaks and figures

8

Cost and Found

9

Earlier this year, Siemens handed over its first oil-free steam turbine

Statoil starts up the world’s first subsea wet gas compressor

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

FoundOcean highlights its strategy for minimising costs in offshore operations

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

UNCONVENTIONALS 11 US shale drillers refrack 12

Editor Andrew Dykes andrewd@newsbase.com

Several US shale drillers are focusing on mature fields, vertical wells and refracking

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

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in exploration, production

and refining November 2015

View from the Summit

22

A find down under

25

Oil sand extraction

26

Where are they now?

28

News in brief

30

Moving on UPPP

36

Suncor’s cleaner and more efficient way to extract Canadian bitumen

NONFRICTION Siemens’ magnetic oil-free steam turbine

Previously-featured companies

Page 20

OCEAN OF SAVINGS

FoundOcean discusses offshore cost-efficiency

Page 12

20

Falcon Oil & Gas explores Australia

Issue 39

A look at the companies and technologies leading the US trend

A flare for innovation

Policy making and technology at the European Shale Gas & Oil Summit

NEWSBASE

RETURN OF REFRACK

18

Primus Green Energy changes the economics of small-scale GTL

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

Page 9

A Tru story

The story behind the development of Weatherford’s TruFrac® composite plug

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ations Bringing you the latest innov

16

The advanced materials holding fracturers open

Phone: +44 (0)131 478 7000

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New proppants

An innovative online gaming platform to spark interest in E&P

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Contacts 38 NEWSBASE

At Safehouse our mission is to protect people, preserve assets and improve production by making hot work in a hazardous environment universally safe.

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November 2015

InnovOil

page 5

A note from the Editor The unconventionals sector has had an interesting year to say the least.

Not much longer ago than this time last year, predictions for US tight oil output were still growing exponentially. Even as oil prices began to dip, drillers continued to ramp up output, with production from the prolific Bakken peaking last December.

During 2015, various narratives have been spun by the industry and its commentators, ranging from the early suggestion of steady output enabled by greater efficiencies and resilient firms, to a sector-wide route for drillers. The truth, as always, is somewhere in between.

In talking to technology providers while preparing this issue, it remains surprising and encouraging how much business there is still be done. As many operators look to new and better technology and equipment to make their assets more efficient, innovators would appear to have the ears of more buyers than ever before – if their products are proven.

Likewise, some market dynamics have opened the space to new players. Primus Green Energy, featured in our unconventionals supplement, has developed STG+ – a system for use in small-scale gas-to-liquids (GTL) conversion. Interest in its innovation is being driven, in part, by the ultra-low price of natural gas in the US, as producers look to recapture value which may otherwise be lost via gas flaring. Primus COO George Boyajian explains more inside.

Refracking is another trend which has gained momentum during 2015. With producers now running extensive refracking campaigns to squeeze further production from

their existing assets, services providers – including Halliburton and Schlumberger – are now stepping up their ability to cater to a new market. NewsBase’s North America editor Anna Kachkova weighs in.

We also speak to Weatherford about its TruFrac® composite frac plug, examine new developments in proppant design, chat to Falcon Oil and Gas about its Australian exploration programme and report from this month’s European Shale Gas and Oil Conference in Manchester.

Outside unconventionals, interesting developments of course continue. On our cover is Siemens’ SST-600, an (almost) oil-free steam turbine deployed earlier this year to generator Vattenfall. Unlike conventional turbines, this uses a system of magnetic bearings to suspend the rotor, leaving it literally floating and removing the need for lubrication. The innovation could have interesting applications for oil and gas, especially in hazardous areas where large quantities of oil present safety concerns.

FoundOcean also details its strategy for cost and efficiency in offshore operations, Statoil reports on the world’s first subsea wet gas compressor at the Gullfaks field, and we hear from previous InnovOil contributors about how their innovations fared in our Where are they now? feature.

Aberdeen recruiters Petroplan also feature the latest oil and gas jobs on offer in our recruitment section, while MOL Group discusses its UPPP programme – an innovative digital competition which sees graduates battle it out for technical placements.

The team and I are pleased to bring you the November edition of InnovOil.

Andrew Dykes Editor

NEWSBASE

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InnovOil

The rotor literally floats on a system of elctro-magnetic bearings ...

November 2015

Time for an oil change?

Earlier this year Siemens handed over its first oilfree steam turbine. We caught up with project manager Christoph Grund to hear about the project’s development

T

... meaning no loss of energy to friction

NEWSBASE

urbines make the world go round. Whether powering cities or platforms, steam and gas turbines are the primary means of keeping the lights on, as well as a host of other vital processes. Yet while they are an indispensable part of almost most major engineering operations, the concept has not seen much refinement beyond incremental gains in design, manufacturing and materials. They also require regular servicing and maintenance, not to mention a healthy supply of oil for bearing lubrication.

That is, until earlier this year. In June, Germany’s Siemens announced the delivery of the world’s first oil-free turbine.

Unlike conventional turbines, the SST-600 uses a system of magnetic bearings to suspend a rotor weighing up to 10 tonnes.

The rotor literally floats, removing the need for a film of oil between itself and the bearings – and eliminating the need for oil tanks, lines, pumps and disposal systems, and of course the hundreds of litres of oil within them.

The resulting turbine is therefore smaller and more efficient. No contact with the bearings means no loss of energy to friction, and the system is up to 1% more efficient – not an earth-shattering statistic in itself, but as Christoph Grund, Siemens’ oilfree steam turbine project manager told InnovOil: “A higher efficiency of up to 1% is a huge development when bearing

November 2015

InnovOil

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The sytem installed at Vattenfall’s Jänschwalde lignite-fired power plant in Germany

in mind that steam turbine technology itself has hardly any potential for further development anymore.”

While “oil-free” is perhaps misleading – the system contains between 3-10 litres of oil to lubricate the valve actuators which control the steam supply – the efficiency and safety gains make this an attractive investment. Installations with sensitive environmental or safety considerations, especially around fires and fire safety, may therefore find it a very prudent investment.

Cooling challenges The turbine has been in development since 2007 as part of a collaboration between Siemens and the Zittau/Goerlitz University of Applied Science, the latter of which provided a test bay in which to develop and refine the bearings.

Siemens adds that: “From a technical

perspective and depending on the operating materials necessitated by operating conditions, any Siemens steam turbine with a rotor weight of up to 10 tonnes and an output of 45 kW to 40 MW can also be equipped with magnetic bearings.”

Active magnetic bearings – whose force is controlled via electromagnets – are used in a number of other technologies such as compressors and electric motor, but Siemens is the first to deploy the system to a steam turbine. This is mainly owing to the fact that steam turbines are subjected to immense temperatures and temperature change. Overcoming this, Grund says, was a newly designed cooling system. “The challenge of a steam turbine is the heat it operates with. The average inlet steam temperature is about 500°C, thus we have a hot surrounding near the bearings. Siemens NEWSBASE

solved the challenge with a distinguished air cooling system,” he explains, the design of which Siemens has now patented.

In active magnetic bearings, the position of the rotor is registered by sensors and controlled by a system that adjusts the magnetic field. Here, a SIMOTICS system – a control system used in Siemens motors – compensates for all the weights and process forces acting on the rotor.

Because they are controlled digitally, the rotors can also be potentially monitored online, aiding elements of production efficiency and condition monitoring.

The system is also not limited to this particular model, as Grund highlights. “The magnetic bearing and electrohydraulic valve actuators which both lead to an oilfree steam turbine are not specific to one certain product line. It is applicable to steam turbines with a rotor weight up to 10t and we could adapt it to several product lines,” he adds.

To help minimise the amount of oil used in the actuators, the designers also incorporated a compact hydraulic system – another way in which the team could ensure the machinery maintained a smaller footprint.

The turbine’s first commercial deployment has so far been a success. In February, Siemens delivered a 10-MW prototype unit to Vattenfall’s Jänschwalde lignite-fired power plant in Germany, where it was set up in tandem with a further 11 conventional turbines used to pump feedwater. It has since been operating at full load at a speed of up to 5,700 rpm, and in June a final model was installed and handed over to the Vattenfall.

Grund says that since the installation and official handover, the response from industry has been great. “We experienced very positive feedback and interest and were congratulated as an innovative company. We appreciate the feedback very much.” n

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InnovOil

Gullfaks and figures

November 2015

Statoil’s pioneering subsea developments continue, with the completion of the world’s first subsea wet gas compressor at the Gullfaks field

O

ctober has signalled yet another major month for Norwegian NOC Statoil. Even in a year already full of massive contract announcements and development milestones, the completion and installation of a world-first piece of subsea engineering should still prove a highlight.

Following the installation of a similar pioneering subsea compression system for dry gas at its Åsgard field in September, Statoil, Petoro and OMV have completed the commissioning of a wet gas compressor at the Gullfaks South satellite field. The system was first installed for testing to begin in March this year, and the October 12 announcement by Statoil marks the completion of efforts dating back to 2012.

The 950-tonne system will compress wet gas and liquids together on the seabed at a depth of 135m, without the need for separation. Designed by Framo Engineering and delivered by OneSubsea in collaboration with Statoil and Shell, the set-up features “a contra-rotating machine specifically designed for pressure boosting of unprocessed wellstream.”

With both phases treated in the same system, and as close to the well as possible, overall production is greater, faster and more efficient, from a smaller and lighter subsea template. This compact design allows the compressor to be installed by a light intervention vessel

(LIV) rather than a larger constructor.

Following compression, gas is then sent through a 15-km tieback to the main Gullfaks C platform where it can be processed. The platform also supplies power and controls to the template’s two 5-MW compressors. These are capable of compressing the gas and liquid to 32 or 60 bar – depending on whether they are run in parallel or connected in series – and can handle up to 10 million cubic metres per day. OneSubsea also reports that the lack of a surge risk means that no anti-surge system is needed, again lowering the overall weight and footprint.

The factory floor The system, and Statoil’s wider push towards what it calls the “subsea factory”, is an important step for both engineering and overall recovery hydrocarbon recovery.

According to Statoil senior vice president for west cluster operations, Kjetil Hove, “This is one of several important projects on Gullfaks for improved recovery and field life extension. The recovery rate from the Gullfaks South Brent reservoir may be increased from 62% to 74% by applying this solution in combination with other measures.”

In figures, it estimates this at around 22 million barrels of oil equivalent (3 bcm gas). As well as extending the life of fields like Gullfaks and Åsgard – the latter’s compressor is touted to boost recovery

NEWSBASE

from the Mikkel and Midgard reservoirs by 306 million boe – technologies like this will be vital in meeting Statoil’s goal of raising average Norwegian recovery rates to 60%.

“We see great opportunities for wet gas compression on the Norwegian Continental Shelf [NCS],” Hove added. “It is an efficient system and a concept that can be used for improved recovery on small and medium-sized fields. We are searching for more candidates that are suitable.”

These additional candidates could also be tied into the Gullfaks facility, which has been designed to incorporate potential additional wells in future. This feature is also indicative of the wider push for standardisation, a move hinted at by Statoil’s executive vice president for technology, projects & drilling (TPD), Maragareth Øvrum, who commented: “The concept may be standardised by applying well-known technology components.”

For now, next year might be a little quieter, as development efforts at Johan Sverdrup continue. A Statoil TPD spokesman confirmed to InnovOil: “We have no specific development plans which include the realisation of subsea compression in 2016.”

Yet its potential is significant. The spokesman concluded: “Based on the experience achieved through [Gullfaks and Åsgard], subsea compression will be considered for use in the future, both on the NCS and in other basins.” n

November 2015

Cost and Found

InnovOil

page 9

Offshore construction firm FoundOcean highlights its strategy for minimising costs in offshore operations

L

ower prices and a bearish market has seen cost reduction move up the agenda of all companies in the oil and gas industry, regardless of their position within the supply chain.

While there is no simple solution to project completion time or related costs, experience suggests that the more time is spent during onshore planning, the higher the likelihood the project will come in on budget. As such, international offshore construction firm FoundOcean is a firm believer in planning ahead.

Expect the unexpected All offshore companies plan for the things that can be controlled, and have contingencies for those that cannot. Time is a key contributor to uncontrollable costs.

Detailed operational procedures coupled with schedule-planning means that time offshore will be efficiently used.

Again, experience shows that offshore, one should expect the unexpected. The ability to plan multiple contingencies will always offer the project a much greater chance of staying on schedule. To do this effectively, anticipating which problems are most likely to occur is something that only experience can teach.

Additionally, the harsh environment in which contractors work puts added pressure on how personnel and equipment perform.

In a recent offshore tidal turbine foundation project, the installation contract was originally awarded to an onshore civil engineering company who had vast experience of installing foundations for

onshore renewables projects. By choosing a contractor from within the same industry, but without the offshore experience, the project fell behind schedule by some months. The developer then approached an offshore installation contractor, who in turn appointed FoundOcean.

Working together, the two companies mobilised and installed the foundation.

From initial contact to demobilisation, the project was completed in just 20 days.

Integrated project schedules Developing an annual schedule of works, which includes multiple projects in one mobilisation, can benefit all companies within the supply chain. This type of work schedule is best led from the developer, as they have a clear picture of all the projects in their pipeline.

Work in the same region can be grouped into a series of mini-projects within one larger scope of work, encouraging contractors to bid more competitively for a high-value project than for a series of lower value contracts.

This approach allows companies to better allocate both personnel and equipment to projects, ensuring that people with the right skillsets are deployed with the most appropriate equipment for the full project duration. This reduces the need to load and unload heavy equipment, set and unset sea fastenings, and redesign deck plans for each project.

Short-term gain vs. long-term pain FoundOcean recently completed three projects where localised seabed scour had NEWSBASE

occurred around a jacket structure. In all instances, the hydrodynamic loading was causing the crown-shim welded jackets to move about the driven piles. This movement could be felt in the topsides and was expected to reduce the life of the jackets, had it not been rectified.

The solution was a two-stage fix. Firstly, a donut-shaped fabric formwork was installed and grouted under and around each mudmat. The grout bag would act as a support for the mudmat and form a plug for the leg pile annuli later on. After the fabric formwork had cured, the remaining void was filled with grout to ensure even weight distribution. Next, a cement grout was injected into the leg pile annuli to strengthen the connection and eliminate jacket movement.

This type of remedial work is not uncommon in the oil and gas sector, and is a result of the cost-benefit analysis of one installation method over another i.e. crown-shim welded against the grouted method of securing structures to the seabed.

However, these real-life examples are a clear indication that sometimes the more expensive option can be best, especially when one considers the associated costs which can be incurred when returning to undertake complicated repairs at a later stage in the asset’s life. n Contact:

Alexandra Leo Tel: +44 (0)1628 567 000 Email: Alexandra.Leo@Foundocean.com Web: www.foundocean.com

ACE Winches lead the world in the design, engineering and manufacture of winches and deck machinery, equipment hire and the provision of associated hire personnel for the energy industries.With a broad range of capabilities, expertise and knowledge, in products and services for the Offshore, Onshore and Subsea markets, ACE Winches is a trusted partner.

ACE Winches is the expert partner to manage the total project solution from concept design through to manufacture, testing, installation, commissioning, operation, training and ongoing client support.

www.ace-winches.com ACE Winches, Towie Barclay Works, Turriff Aberdeenshire, AB53 8EN t: +44 (0) 1888 511600 f: +44 (0) 1888 511601 ACE Engineering

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InnovOil

Unconventionals

November 2015

Special supplement Pages 11-27

Based on a Tru story The development of Weatherford’s TruFracŽ plug Page 18

Sand and deliver

How proppant design is pushing shale forward Page 16

ESEIEH does it

Suncor is using radio frequencies to extract oil sands Page 26

NEWSBASE

page 11

page 12

InnovOil

November 2015

Unconventionals

US shale drillers fall back on vertical wells, refracking Several US shale drillers are focusing on mature fields, vertical wells and refracking in an effort to sustain cash flow as the downturn continues, write Anna Kachkova and Andrew Dykes

U

S producers that have until recently been focusing on horizontal drilling are increasingly turning back to vertical wells, mature fields and refracturing as ways of sustaining cash flow as oil prices remain low.

Reuters reported last month that while initially the availability of funds, supersized frack jobs and steep discounts on oilfield services and equipment had helped to sustain production as prices fell, now producers were shifting their focus from output growth to capital discipline.

“It makes more sense to develop vertical wells in a lower price environment because they are not growth plays but they are a very strong cash flow asset,” a Wood Mackenzie principal analyst, Benjamin Shattuck, told the news agency. “They are going to give you that cash flow that you need today.”

According to Baker Hughes figures, the US vertical rig count has risen by around 20% in recent months, from 99 in early June to 110 rigs in the week of October 23. The horizontal rig count meanwhile, has dropped from 673 to 591. With tens of thousands of older onshore wells in existence in the US, the fresh focus on them is already resulting in new output.

Shifting focus Companies shifting their focus to mature fields and vertical wells include Devon Energy, Noble Energy and Apache, among others. In meetings with investors earlier in September, all three companies devoted more attention to mature oilfields and vertical wells than they had done previously.

Devon has been one of the leaders in terms of refracking older wells – particularly vertical wells – in North Texas, as the process is cheaper than drilling and fracking new horizontal wells.

“Even in a mature area like this, there’s upside our technical teams are looking at,” Devon told investors in September.

Devon said it had refracked 150 vertical wells and was testing the technology on older horizontal ones, where the process is less predictable.

Noble said it anticipated producing more than previously expected during this quarter, with its performance boosted in part by vertical wells at the company’s Denver-Julesburg Basin acreage in Colorado. Noble has raised its anticipated third-quarter sales volume range to 360,000-370,000 barrels of oil equivalent per day, representing a 10,000 boepd

NEWSBASE

increase on the midpoint of its prior estimate.

“Production from our legacy vertical wells and older horizontal wells [is] benefiting from substantially reduced line pressures and improved third-party plant uptime,” said Noble’s executive vice president of operations, Gary Willingham, in a statement.

Apache, meanwhile, is focusing on its legacy oilfields in the Permian Basin, where it has both horizontal and vertical wells.

“We’ve got a lot of low-hanging fruit in terms of little quick projects you can do and get your money back in six or seven weeks and add significant barrels,” Apache’s CEO, John Christmann, told the Barclays CEO Energy-Power Conference.

Christmann went on to say that the company would invest more in the region – which accounts for 27% of Apache’s output, or around 77,000 boepd so far this year – if prices remained low.

Cheaper options Vertical wells and mature fields are currently looking attractive to drillers because they allow them to produce more at a lower cost. They generally require less

November 2015

InnovOil

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Unconventionals Fracking in Colorado

powerful rigs that are cheaper to rent, and take less time to drill.

Reuters noted that whereas a large horizontal well could take a month or longer to drill, a shorter vertical well might take as little as 10 days to be brought on line.

While shale drillers have recently brought about considerable reductions in the cost of drilling, company data indicate that a horizontal well of around 10,000 feet (3,000 metres) can cost around US$5-9 million to drill even with the discounts currently available. Meanwhile, a vertical well can be drilled or refracked for around US$1 million.

Refracking is proving attractive for similar reasons. Earlier this year, it was reported that refracking a well costs around US$2 million. While results from refracking have been variable thus far, the increased use of the technique in recent months is already leading to improved performances. Indeed, in Devon’s Q2 earnings presentation, it reported that “[vertical] refrac costs have declined to as low as US$270,000 per well.”

This could be expanded into horizontal refracks. The company added that during H2 2015, it would “continue to evaluate

the commerciality of this opportunity by testing refracs on up to 15 horizontal wells.” Its latest update, due in the next few weeks, should provide a decent indication of whether or not it has been successful.

Reactive strategy Halliburton also looks to be making good on the US$500 million it received from Blackrock in July to help enable its ACTIVATE Refracturing Service.

The scheme incorporates a number of disciplines, including a stimulation service, coiled tubing, the FracInsight Service, Pressure Sink Mitigation and other expertise. The result, it says, is that refracks are “more reliable and predictable.”

Indeed, Halliburton president Jeffrey Miller told reporters on a call following the company’s Q2 earnings results that the company saw “a significant runway for refrac in the future.”

If you believe the figures, he appears to be right. The firm reported that the service was seeing up to an 80% increase in estimated ultimate recoveries (EURs) per well, up to a 25% increase in oil recovery factor and a reduction in cost per boe of up to 66% compared to new drilling. In the oil window of the Eagle Ford, Halliburton’s

NEWSBASE

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InnovOil

November 2015

Unconventionals

technology was reported to have raised the average EUR of wells by 121%.

In line with producers, Halliburton is so far focusing on the lowest hanging-fruit and lowest-cost wells before moving onto more wells that require more sophisticated work. It also noted that while not every well would see such dramatic improvements, Halliburton had not had a single well negatively affected by a refrack.

Diversion tactics Meanwhile, in August Schlumberger reported that it had eight refracking clients in North America. This figure too is likely to grow, evidenced by the fact that at the end of September the firm signed a licensing deal with the UK’s Highland Natural Resources for Diversion Technologies’ DT Ultravert, a system with potential in the refrack market.

The deal is a coup for Highland, which only acquired a 75% interest in Diversion’s patent applications in May this year.

According to Schlumberger, while current diversion technologies operate near the well bore, DT Ultravert penetrates into the reservoir and diverts where oil and gas have already been produced. “The DT Ultravert process injects gas into the

depleted area of the reservoir and repressurises the area, forcing the refracture fluid to divert to under-depleted areas,” it adds.

The process also uses non-damaging gases – most likely nitrogen – which flow easily back to the surface once the well is in production.

With potential for “easy deployment anywhere in the world,” the technology is evidently exciting enough for Schlumberger to snap it up.

The acquisition adds to Schlumberger’s stable, which already includes the company’s touted Broadband Sequence service, a system which claims to have increased the productivity index of a refractured shale well by 600%.

In a recent interview with Canada’s Oilweek, the company’s technology integration manager, Andrew Acock, commented: “We’ve brought some very low producers back to 70-80% of their original production rates with pressures coming back up to the original levels… [Successful refracked wells] have enough production to pay the refracture costs under one year and increase the returns.”

While noting that “It’s still early in the game,” Acock concluded that the firm was

NEWSBASE

“taking a relatively simple approach, but it does seem to be economic if you do the proper candidate selection. We are excited about the opportunities for refracturing.”

What next?

While there has been scepticism over the potential of the refracking market, given the ongoing unpredictability of results, new testing is helping drillers to hone their techniques. Now with services firms making technology acquisitions, and launching refrack campaigns, the discipline could see a lot of advances in 2016-17.

Combined with a focus on the easier targets – mature fields and vertical wells – the technique seems set to make at least some impact and become yet another factor helping the US to maintain production, with only modest declines in the short term.

“What’s important to remember is that in spite of the low commodity price, mature fields – they are more resilient,” Halliburton’s Miller told investors last month. And this resilience could become even more attractive to producers as they work out their strategy for the coming months and years. n

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InnovOil

page 16

November 2015

Unconventionals

New proppants open up the unconventional market

Jeremy Bowden reports on the advanced materials and innovation now being applied to proppants used in hydraulic fracturing operations

O

ver the last few months, advances in technology have helped sustain US unconventionals production despite a crash in prices. Among the key areas of development are the materials injected into the shale rock to hold fractures open, known as proppants.

Initially, the proppant used in hydraulic fracturing was simply sand, but other materials are increasingly being employed.

There are resin-coated sands and ceramiccoated sands, more recently there are deformable polymeric proppants, and even a proppant composed of sintered (powdered) bauxite – tiny manufactured rocks. By using these materials to create the proppant it has been possible to vary its properties – including size, shape, strength and weight – more easily and accurately. By adjusting these properties, the optimum pathways can be maintained by the proppants for the extraction of hydrocarbons, increasing the conductivity, or the amount of flow that the proppant will allow.

Physical size typically ranges between 106 µm and 2.36 mm (or in proppant units between 8 and 140 mesh) to suit the structure of the shale, allowing hydrocarbons to be more effectively released. Proppant geometry can also be controlled, with certain shapes more effective in particular rock structures.

Ceramic and resin proppants have superior roundness than sand proppants and are more uniform. When used, these give the fracture greater permeability and higher fluid retrieval rates. Resin-based proppants can also contribute to reducing the environmental burden related to fracking by cutting the volume of water or other ingredients required.

Generally the strength of proppant is directly correlated to its weight – the higher the strength, the greater the weight.

But the new materials have also enabled lightweight proppants with sufficient strength to withstand higher pressures.

Lighter proppants are able to travel further into the formation, as they stay suspended in fracking fluid longer than their heavier counterparts. They also allow downhole engineers to deliver the required high volume of proppants safely, without exceeding weight limits, whereas previously the ratio of proppant to fluid had to be below optimum levels.

Pressure and depth The new materials offer huge potential for a large range of drilling applications.

Weight or density can be adjusted, with deeper, higher pressure fracks benefiting from a heavier, more robust proppant with a higher crush resistance. Weaker sand proppants can disintegrate into smaller bits which then occupy the gaps between the

Various resin-coated and ceramic proppants from Hexion NEWSBASE

fractures resulting in loss of hydrocarbon flow. In some environments proppants also need to be acid-resistant, requiring the right combination of materials.

As global energy demand continues to increase, deepwater/high pressure (DWHP) and acidic oil and gas reserves are projected to make up a greater share of long-term supply. Unconventional techniques are anticipated to be used more and more for enhanced oil recovery (EOR) at conventional wells – as well as for deep shale plays. Ceramic proppants are particularly effective in deeper drilling, where the fracture closure pressures are higher, owing to their greater crush resistance.

One firm, Melior Innovations, has developed what it claims is a step-change in proppants using a highly specialised material new to the oil and gas industry, designed to optimise production from DWHP wells. The material is consistently able to reach four key performance requirements – strength, weight, spherical shape and uniformity. It is also designed to resist extreme cyclic loading conditions for the life of the well.

High strength gives it the ability to operate at closure stress levels, and its light weight enables it to travel further into fractured formations, delivering increased hydrocarbon recovery. Finally, the spherical shape and uniform size ensure

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Unconventionals

optimal conductivity throughout the proppant pack, delivering higher ultimate recovery levels.

CARBO Ceramics, meanwhile, has produced what it calls an ultra-high conductivity proppant technology for deep wells. The product is being used by a major operator in the US Gulf of Mexico’s Lower Tertiary trend, marking the largest and deepest job for these proprietary technologies to date. The technology provides higher production and estimated ultimate recoveries (EURs), maximising the operator’s ROI. Some new proppants are also incorporating scale-inhibiting chemicals, which are released steadily over a set period, resulting in long-term protection against the formation of common oilfield scales over the whole production network.

and quantity, which provides an accurate measurement of perforation cluster efficiency and near-wellbore connectivity.

This can help to maximise EURs. Understanding proppant placement also supports the optimisation of stage placement and proppant diversion. The information gathered enables operators to reduce costs and ultimately improve their completion efficiency.

Momentive Specialty Chemicals was among the first companies to offer proppants tagged with non-radioactive tracer technology to track proppant distribution, under its PropTrac fracture diagnostics service. UK-based Tracerco also produces a range of chemical tracers, and has recently been developing a new suite of proppant tracers which last even longer downhole.

Traceability Innovators are also offering easily detectable inert tracer technology for completions in both vertical and horizontal wells. Traceable proppants are detectable with a standard neutron logging tool, and can be mixed with sand or other proppants before injection. The tracer does not dissolve or wash away and is permanently identifiable, providing operators the flexibility to conduct post-fracture logging months or years after fracking.

The technique enables the detection and evaluation of near-wellbore proppant location

Stress bonding Companies have also developed curable resin-coated proppants that can bond together under the correct amount and type of stress and temperature, which are designed to help protect against proppant embedment and flow back. Proppant flow

NEWSBASE

back can be an issue in certain formations where, as the well produces, it forces proppant back into the wellbore, which can cause serious damage to surface equipment.

The resin-coated proppant is curable so it only bonds under fracture conditions, when there is differential pressure causing closure stress, within a range of temperatures. This ensures the bonding takes place only when the proppants are pumped into the fractures, rather than in the vertical wellbore or a horizontally drilled lateral.

Currently the proppant market is still dominated by sand, with 80% of wells using it at an average rate of 5 million pounds (2.27 million tonnes) per well, costing over US$100,000 each. The other 20% is split between resin coating and ceramics, with pioneering materials making up only a tiny proportion.

This fact that these advanced materials remain only small proportion of the overall market suggests that the innovation process has only just begun.

But just as in any other young industry, we can expect to see rapid development continuing throughout the early years, and with more and more attention being given to unconventional techniques – now even applying them in conventional reservoirs, as a recent IHS study suggests – opportunities in both the advanced materials and high-spec proppant markets appear considerable. n

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November 2015

A Tru story Unconventionals

The TruFrac® Composite Plug

Upper Slip and Cone

Molded Element System

Lower Slip

Mule shoe and space for optional pump down ring.

Weatherford’s global product line manager for composites, Matthew Crump, tells the story behind the development of the company’s TruFrac® composite plug

E

fficiencies in the fracing market are based on the need for speed.

Speeds of setting, perforating, pumping, milling and producing, among other improvements in precision, have ground down completion times year on year, month on month. Staying on top of this is proving a welcome challenge for some of the industry’s biggest innovators.

Economics have also changed what the market wants. Whereas last year saw plugand-perf and sliding sleeve completions split roughly 75:25 respectively, improvements in technology and the fall in prices have prompted a slide further in favour of plug and perf. Weatherford global product line manager for composites, Matthew Crump, reckons this now accounts for around 85% of completions in the US. “They’ve discovered they can get better production if they run cased-hole wireline logs to pinpoint the frac to certain pieces of the reservoir in a more educated manner than how they did in the past,” he explains to InnovOil by phone from Houston. In order to do this, he says, operators want the flexibility to run wireline logging systems once their casing is installed, something that sliding sleeve completions do not offer.

With this shift in the market, Weatherford saw an opportunity to refine its frac plugs to enhance the efficiency and time taken to run plug-and-perf completions.

Faster by design The TruFrac® composite plug offers some interesting advances both in composite NEWSBASE

moulding, and in overall system design.

Suitable for vertical, deviated or horizontal wellbores, the use of a 97% composite blend allows the plug to be run in and milled out faster than most other plugs on the market.

Crump is keen to stress the back-tobasics approach the team took when examining how they could enhance the product: “In 2013, we realised we needed to make a step-change in our composite technology. From then until the beginning of 2014 we did product development, design and lab testing.” He outlines the three main considerations which informed their approach.

“The first thing when designing a composite plug is to ensure it’s robust enough to get where it’s going to perform its duty,” he points out. The plug needs to reach the desired depth in the well without snagging on the well casing or being damaged by pump fluid. Once in place, it needs to seal securely enough to stay in place, and to make sure the frac fluid reaches the desired part of the formation.

“Third and most important,” he continues, “operators want to remove the plugs to produce [by milling], so customers are interested in how fast they can mill out all the plugs, and how big are the pieces which come up when they do. On average,

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Unconventionals

milling time in the Eagle Ford is somewhere between 20 and 25 minutes. Doing that over and over in a 35-stage completion can add days to your operation, before the well even produces.”

“In the past, in much older technology with cast-iron plugs, etc., the pieces that came off the milling would be big, and when they’re big you have a higher chance of your milling assembly being stuck downhole,” Crump says. It is in addressing this problem that the inherent advantages of composite materials become more apparent.

Composite solution “The crux of the design was creating a composite lower slip system with the least amount of metal as possible,” Crump explains. Although drawing from a number of years of experience – Weatherford has been in the market since 2002, when it partnered with a manufacturer to develop the first generation of composite plugs – the complex moulding of a new design for the lower slip led it to partner with another outside manufacturer.

It involved a great deal of fundamental testing over 2013-14, in order to create an easily millable material which would stand up to the 10,000 psi and 150°C (300°F) downhole conditions. After working with the supplier to develop and test a number

of different moulds and materials, Crump says, the team “settled on a segmented design which holds four small metallic inserts – these bite into the casing and create an anchor. They are then are held together with composite bands that break once the plug is set, allowing the slips to bite into the casing.”

The result is a plug which, on average, mills out in around 10.5 minutes.

Test your metal Gains were made in other parts of the assembly too. By reducing the amount of metal in the overall system – the upper slip and element included – the TruFrac could be made smaller and faster to deploy and remove.

“Since a frac plug is only holding pressure from above,” Crump says, “the lower slip is what does all the work and holds all the pressure. When you look at most of the plugs on the market, everyone works really hard on the design of the lower slip to make sure it can hold 10,000 psi at 300°F – then they just reverse that and throw it on the top.”

“The result is an upper slip that has a lot of metal in it, and a lot of high-strength composites, and is really just over-designed for the frac plug. So we designed a fit-forpurpose upper slip – filament-wound with NEWSBASE

small powdered metal buttons – that is easily millable and has the least amount of metal as possible, just to hold the setting force of the plug,” he continues.

The element system, the section of the plug which seals and holds the well pressure during a frac, was also redesigned.

Traditionally, it poses the most concerns when being pumped downhole. The rubber section, vital to providing a robust seal, can flare out or become snagged on the casing. In order to ensure the element stays put during the frac most plugs employ an exposed backup system too – but these also can create extra lips and profiles which can become snagged in the wellbore.

Crump elaborates: “Historically, Weatherford’s plugs had an exposed system, but when we were looking at how to pump it down efficiently, we really wanted a system that was completely smooth on the OD [outer diameter] but still had the composite backup system to hold the seal in place.”

The solution was to incorporate the best features of the existing design into a new rubber element. “We took our composite backup system which had proven to be reliable in our previous designs, and designed an element where that backup was moulded directly into the rubber of the element itself,” he says. This creates a completely smooth OD on the element, offering what the company believes is “a superior seal” compared to other plugs.

At a total length of 23.44 inches (595 mm) the plug is small in comparison to its rivals, again contributing to a much reduced mill-out time. Over a 35-stage frack, this adds up. “That can be up to 18 extra feet of material you have to mill out!”

Crump says.

Results with TruFrac have been positive so far. Its testing phase saw 16,000 runs with 99.9% reliability – a key factor, Crump says, in qualifying its abilities to customers.

With further cost reduction and efficiencies on the minds of customers, Weatherford is now looking at incorporating newer composites into its design, and shortening its plugs even further. “We’re trying to push the bounds of composite strength and design,” Crump affirms, adding: “We’re in later stages of testing for dissolvable technology, which is the next step in plug-and-perf.” n

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November 2015

A flare for innovation Unconventionals

Primus Green Energy believes that its innovative STG+™ process dramatically changes the economics of small-scale GTL, helping to reduce flaring and recover value for unconventionals producers

G

as-to-liquids (GTL) technology is often only considered as a last resort. For most operators, it is a solution examined out of necessity rather than economics – the result of crippling supply logistics or working in remote locations.

When it is economical, it is on the scale of billions of dollars. But if it can be made cost-effective, it could prove to be a transformative approach to a wide array of operator problems.

One major result of the US’ shale boom has been a glut of natural gas, and a corresponding fall in prices. Even with multiple LNG trains, it has far more than it could consume, and nowhere near infrastructure to move it all around. The result, for many producers, is simply to flare associated gas from oil wells, for want of being able to produce a valuable or usable product. According to data from the EIA, the volumes of vented and flared gas have more than doubled since 2008, to around 290 billion cubic feet (8.2 billion cubic metres) in 2014.

Globally, some estimates suggest

producers and refiners flare US$50 billion of gas per year. Even if one disagrees with the price, it is a lot of money. Even with a supply glut, recapturing even a small chunk via technology such as GTL is a worthwhile proposition.

Lowering the volume In general, the problem with GTL is volume. The most efficient and economical plants rely on massive scales and massive feedstock supply to maintain viability. Most GTL technologies currently in use are only economically viable if they can produce 100,000 barrels of fuels per day; even a large single-well flare in the Bakken may only manage 250 bpd.

Enter US-based Primus Green Energy.

In developing its proprietary STG+™ technology, the New Jersey-based firm believes it can also dramatically change the economics of small-scale GTL operations, and with it, recapture some of the value otherwise lost from flared gas.

Its system converts synthetic gas (syngas) to gasoline (or alternatively, methanol)

Gas flaring in the Bakken.

Primus hopes to recaptue some of the lost value via its GTL technology

NEWSBASE

via a catalytic thermochemical process, at an efficiency of around 70% by mass.

In Primus’ GTL system, associated and/or natural gas undergoes steam methane reforming to become syngas, before the STG+ process then coverts it to high-quality usable fuel. The company’s chief commercial officer, George Boyajian, broke the results down into numbers. “STG+ converts around 1 million Btu of natural gas to between 4-5 US gallons (14-18 litres) of gasoline, or double that for methanol,” he told InnovOil by phone, speaking from a GTL conference in London.

In terms of plant capacity and feedstock, the smallest units will provide up to 500 bpd or 160 metric tonnes of methanol from 5 million cubic feet (140,000 cm) of gas. This can be scaled up to 2,000 bpd with the aid of a larger methanol reactor, and with the potential to scale up further via additional trains if required. “This,” Boyajian explains “is based on the largest methanol reactor we can safely put on the back of a truck in the US and get through underpasses.

From there, we would build multiple trains to scale up, and you do see significant savings at the larger [of those] scales.”

The result offers producers an additional revenue stream from gas which would otherwise have been flared, and at a far smaller scale than the market has seen work before. “It’s not necessarily more carbon-efficient [in terms of fuel conversion rates] but a lot more capitalefficient,” Boyajian adds. In a world of ultra-low gas prices, this may count for a lot.

An additional benefit, both practical and economic, is that the system is modular. The equipment is manufactured and tested at the company’s main site, before it is moved to a pad on-site and connected to the existing infrastructure.

This allows it not only to be mobilised and set up quickly, but also to be redeployed if the operator chooses. “If

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Unconventionals The STG+ equipment can be moved and up and running at another site in 8-12 weeks

it isn’t economical in five years,” he says, “You can pick it up and move it if you need to, and be up and running somewhere else in 8-12 weeks.”

Not only this, but a plant can be up and running within 18 months, rather than the 4+ years it may take to develop a plant of larger capacity.

Tipping the scales So far, the response to the technology has been positive. At the moment it provides particular solutions to particularly thorny problems. Boyajian says: “The people that have been coming to us are people with very specific needs. Maybe it’s energy security, in that they can’t get gasoline where they are but they have natural gas, so we can make gasoline for them.”

Others may come down to a question of pure logistical economics. “With methanol,” he says, “They might be bringing it in from the Gulf Coast at US$0.25 per gallon to get it to the centre

of the US. We can reduce that cost by 75%, and they get a better source of methanol at a lower cost.”

Although he avoids quoting a costper-barrel figure for Primus’ technology, he maintains that STG+ is amongst the most competitive options in the sector.

“At large scales, it’s all about the same, but at small scales we’re just so much less expensive to build,” he continues. “We’re well under the US$100,000 per barrel figure that people throw around in the GTL space.”

Innovative integration The success of Primus’ strategy, Boyajian suggests, lies in its reverse-engineered approach to innovation. “Our mode of development is to make a perfect product and engineer the costs out of it – that’s how we approached both the gasoline and methanol systems.”

He is keen to impress that the set-up and expertise of his 50-strong team are NEWSBASE

also key to the company’s capabilities.

“One of the reason we can surmount all these challenges is that everything’s under one roof, we’re completely integrated.

We make our own pressure vessels, we fabricate, we build, we operate, we do all the instrumentation – and that allows us to be very cost-effective.”

The next step is to apply this methodology to other fuels. Diesel and upgrading octane are on the company’s radar, although the process is not yet perfected, Boyajian explains. “We make a beautiful ultra-low sulphur diesel but the economics just don’t work yet,” Boyajian continues. But the firm continues to look at ways of lowering the costs to the point at which the technology may prove successful.

For now, though, “business is good,” he enthuses – and with low natural gas prices expected to stay for some time, Boyajian sees “a great opportunity” to help producers recover value. n

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November 2015

View from the Summit Unconventionals

We report from the European Shale Gas & Oil Summit, where policymakers, technology providers and operators take the pulse of the European sector

T

he shale gas industry came together in Manchester on October 15 and 16 at the European Shale Gas & Oil Summit (ESGOS) with the hope of guiding the shale gas sector towards a safe, environmentally friendly and prosperous future.

Now in its third annual instalment, ESGOS enabled a range of industry discussion through three conferences, an exhibition and networking for its 300 attendees. The summit explored current and future trends within the shale gas, coal bed methane (CBM) and underground coal gasification (UCG) industries across the UK and Europe, with attendance from central and local government, energy institutions, operators, contractors, service companies and stakeholders.

Peel Gas & Oil managing director Myles Kitcher, noted that: “It’s great that ESGOS is being held here in the North of England, where research shows a supply hub for the sector could help deliver a £30 billion boost for the region’s economy. At ESGOS we’ll be looking at how to kick start the industry by taking a strategic approach to master planning and offering the developer’s perspective.”

The UK-focused stream of the conference saw industry leaders reflect upon the country’s unconventional future. Key attention was afforded to redefining the UK economy, supply chain management, fast-tracking fracking approvals, financing shale gas investment and how to create a sustainable and safe UK shale industry.

Environmental Resources Management (ERM) global managing partner for oil & gas, Don Lloyd, considered the UK’s position on the global stage within unconventionals and the steps necessary for progressing the industry within the UK. In light of Lancashire County Council’s July rejections of the Preston New Road and Roseacre Wood sites, Francis Egan, CEO of Cuadrilla spoke of his hope that the company will gain approval to frack in Lancashire and that their appeal process is moving along quickly.

Minimal impact Managing the environmental impacts of shale across the UK also provoked much conversation. Despite vocal and high-profile public concern around the environmental impact of shale drilling, Ground Gas Solutions managing director, Simon Talbot, used the platform to assure that the company have found no adverse environmental impacts with regard to ground and surface water during the projects they have undertaken in the UK. Outside engagement served as a key point of discussion across the conferences.

The need for early engagement with both communities and planning authorities proved a consistent theme throughout, with emphasis placed upon answering community questions and concerns in order to prevent industry misconceptions.

Such a focus was echoed by Industry leaders ERM who outlined new engagement strategies through their workshop “Engagement across the onshore oil & gas sector – What needs to be said, how and by whom?” This emphasised the need to move beyond an “engagement as usual” approach, ERM noting that current methods are no longer NEWSBASE

sufficient. These new and different tiers of engagement are now essential to ensuring the acceptance of the industry on a local and national level.

Technical proposals The latest technological advances also took centre stage at ESGOS with industry leaders Golder Associates presenting their FracMan Reservoir software. Drawing upon their international unconventionals experience, Golder Associates showcased key technical approaches for minimising environmental risk and maximising financial gain.

Through a demonstration of FracMan, Golder explained key techniques for examining how to characterize and analyse fractured shale and coal gas reservoirs in order to optimise well locations, landings and completions.

Golder Associates’ senior hydrologist and geologist, Gareth Digges la Touche, told InnovOil that technology has its part to play, particularly because “there are a lot of perceived risks which can translate into technical risks.” He notes the importance of asking the question: “How do you communicate to the public at large how

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Unconventionals

these technical risks can be addressed in a safe manner and in an economic matter for the operators?”

Technology also has some interesting, if unexpected, crossover potential. In one instance, he cites reservoir monitoring software which was previously used for hydrocarbon analysis, but now “we’re very much using it for things like optimising how much water you might need for a hydraulic fracture.” Other analogues are helpful too, he says: “For example, Golder Associates has a long history in the radioactive waste disposal sector, and what we’re finding is that a lot of the work we’ve done there can be applied into the oil and gas industry.”

Looking ahead Key questions for the coming year will include: How to manage public perception after the full results of the 14th onshore licensing round? Will we see drilling in 2016? What plans and commitments will operators make in the wake of the licensing results?

After the success of this year’s event plans are already well underway for ESGOS 2016. Taking place on the October 4 and 5, the 2016 instalment will

consider the next steps for moving from initial exploration to exploratory drilling.

Over the course of two days, ESGOS 2016 will incorporate an exhibition and conferences covering developments within the following areas: UK & European Shale Gas, Underground Coal Gasification and Carbon Capture Storage.

The UK conference stream will consider the results and impacts of the 14th onshore licensing round. The conference will facilitate new PEDL license holders in fulfilling their license requirements within the given time period. Focus will be afforded to assisting operators in developing a business strategy moving forward, maximising opportunities within the shale industry, establishing a UK supply chain, investment and moving from exploration to production.

Taking place on day one of the event, the UCG CCS Conference will navigate the key debates emerging out of the Underground Coal Gasification & Carbon Capture Storage industries.

Attention will be afforded to exploring current UCG projects from across the world, including the UK, Australia, South NEWSBASE

Africa, Poland and China. The role of CCS to meeting climate change targets and reducing greenhouse gas emissions will also form a large part of the discussion.

The European stream will afford focus to shale developments across the region, with specific attention paid to Spain, Germany and Turkey. The conference will hear from Energy Ministries from across Europe, their stance toward shale gas moving forward and developments of hydrocarbon laws.

Operators will discuss results to date and plans over the course of the next 12-18 months.

ESGOS 2016 will also incorporate technical workshops throughout the course of the event. Workshop topics will include: Drillings & Completions, Hydrology, Stakeholder Engagement and Environmental Impact Assessments. n For more information about ESGOS 2015, or next year’s summit visit, please visit www. esgos.eu or contact Charles Maxwell Ltd. Contact: Callum Flynn

Tel: +44 (0)151 230 2110 Email: callum.flynn@charlesmaxwell.co.uk Web: www.esgos.eu

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November 2015

A find down under Unconventionals

Unconventional explorer Falcon Oil & Gas offers insight into its programme in Australia’s Beetaloo basin

D

espite the much-trumpeted potential of global unconventional hydrocarbon resources, the reality of getting them out of the ground is a much more methodical affair than the conventional oil rushes of history.

As Falcon Oil & Gas CEO and executive director Philip O’Quigley comments: “The challenge of unconventionals is that you don’t have that big ‘eureka’ moment, it is more of a mining mentality, as set-by-step you build up your knowledge base.”

O’Quigley is aware of this process firsthand. In May this year, Falcon embarked on a major gas exploration programme in Australia’s onshore Beetaloo Basin, in the central north of the country. Together with partners Origin Energy (35%, also the operator) and Sasol (35%), the group will survey the 4.5-million-acre license with a view to developing a commercial well programme in 2017.

“We’ve put a huge exploration programme together which is a methodical, very technically-driven programme to cover the next 3-4 years of drilling in the Beetaloo,” O’Quigley says.

“What it does is take the 4.5 million acres roughly and through a series of drilling, and different types of drilling – this year we’re drilling stratigraphic boreholes – that will give us certain technical information. We’re trying to identify thick horizontal sections where you can go after an unconventional play using horizontal technology.”

“We’ll then plan a horizontal programme for 2016, so each year we’ll enhance our understanding of how this play might work out,” he continues.

Armed with this information, he is optimistic that the partners will have sufficient information to begin a drilling

programme in 2017, with a view to developing commercial wells.

Such plans are business-as-usual for unconventional E&P firms, but he continues, “I believe if [the basin] produces, it’ll be the oldest producing rock in the world.” The Beetaloo may well mark a milestone not just for the sector – but for hydrocarbon development in general.

Technical September saw the partners announce encouraging results from the Kalala S-1 well, and the beginning of drilling at the Amungee NW-1. According to a Faclon statement, the former reached a depth of 2,619 metres and encountered “a gross interval of over 500 metres shale gas with net pay exceeding 150 metres,” in addition to “excellent potential for gas mature, gas saturated and quartz rich source rocks.”

So far, so good then.

An update on Amungee, released on October 22, is similarly positive. Reports show continuation of the Middle Velkerri formation, 25 km east of Kalala, and indicating “a highly prospective gas mature depth window.”

NEWSBASE

The expertise and technology of developed by the US shale industry is also aiding the company’s efforts. “Here at least, we have the benefit of a lot of the knowledge of what they’re doing in the US. There is a lot of new technology, such as [Diagnostic Fracture Injection Test] DFITS used as a precursor to doing fracks. Now, instead of a 1,000m horizontal we can do a 2,000-m horizontal – all of that technology improves the chances of the Betaloo of being successful,” O’Quigley says. “In terms of design, in terms of geo-steering, all the way to the compounds from which you design your frack material…”

Although it will be over a year before final decisions on Beetaloo production will be made, initial indications seem highly promising. Falcon, meanwhile, has plenty to be occupied with, as it hopes to move forward with other promising acreage – namely its 7.5 million acres in the southwest of South Africa’s Karoo Basin. It would seem that despite a gloomy outlook for some major producers, there is plenty to be excited about in the unconventional E&P sector. n

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November 2015

Unconventionals

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

Suncor Energy thinks the answer is ESEIEH, writes Tim Skelton

Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH)

S

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The group developing the project began

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Unconventionals The environmental impacts of oil sands extraction are well known, but now there is the potential for it to be much cleaner and more efficient

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

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

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

(CCEMC).

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

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

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

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

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

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

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

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

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InnovOil

November 2015

COMMENTARY Turborunner cross-section

Where are they now?

InnovOil catches up with some of its previously-featured companies, to see how they and their innovations have fared

S

peaking with companies developing or releasing new innovations is always interesting, but it can be rare to hear from those further down the line.

It is not often that we later question how the market, or whether something needed substantial modifications or changed priorities to bring its benefits to the fore. In the spirit of this, we caught up with several of our previous contributors and interviewees to find out what is new, what has changed, and how their innovations have fared in a notoriously cautious industry.

Thinking deeply Deep Casing Tools, a firm which designs and engineers casing and completions technology, has seen international interest increase in its high-speed Turborunner™ and Turbocaser™ Express reaming system.

Last featured in May 2014, the company was already enjoying success, having won the regional award for Venture Capitalbacked Management Team of the Year, in the BVCA Management Team Awards 2014.

Turborunner – also previously marketed as Shalerunner – is a free-spinning turbine tool which begins rotating at low flow rates.

They are designed to run on the end of a production liner or lower completion to remove well bore obstructions by circulation alone.

In addition to being free-spinning, Turborunner also offers a unique operational safety factor. When a turbine

stalls, the circulating pressure reduces by several hundred psi, eliminating any risk of setting a liner hanger or packer in the wrong place, whilst at the same time providing a warning signal at the surface.

TurbocaserExpress attaches to the casing or liner below the float equipment as part of the shoe track. If obstructions are encountered when running casing or liners, circulation is all that is required to start the reamer shoe rotating at high speed to wash and ream the string to bottom.

Deep Casing Tools marketing communications director, Avril Carruthers, told InnovOil that the past 18 months had seen the company build on its foothold in the Middle East and Gulf States, with a growth in sales and orders based on its successes in the region during 2014.

In addition – and despite the oil market’s downturn – taking on new clients in Eastern Europe, and as far afield as Kazakhstan, is an encouraging boost to the company and the technology. Carruthers says that the firm’s USP is that Turborunner is “an enabling technology with a simple approach. We provide the opportunity to get the job done better.”

NEWSBASE

Software success Back in Issue 4, we featured Norway’s Geomec, an independent well and reservoir specialist gearing up to launch its GeoTool (Inject) software package.

Its monitoring and analysing software is designed to prevent and remediate well-injection leakages, allowing operators to monitor and identify problems in real time and alerting them to potential incidents before they happen.

Well-monitoring software is, naturally, a great asset and big business to operators.

Proof of the product’s success came in the form of a raft of recent deals with UK and Norwegian operators, one of which was signed with none other than Statoil.

Geomec CEO Jarle Steen Stueflotten explained to InnovOil: “We have had a very long dialogue with Statoil; they also contributed to the development of the

November 2015

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COMMENTARY Tracerco’s technology allows operators to measure which sections of an existing well are the most productive

product. We ran a pilot with them and that was successful so we then entered into discussion for a framework agreement.”

The market is also a very different place now in comparison with 2012. “At the moment operators are very cost-orientated,” Stueflotten says. “Before, their focus was purely on safe and reliable products, but now it’s much more about cost reduction as well – that’s their primary focus on the North Sea. In the US they’re much more about added production, so it varies a little from region.”

Their product, however, has remained relatively unaltered, save for a change in strategy and a pick-up in interest. “At that point, we had software we sold as a service – now we are able to sell it as standalone software. We’re also splitting it further so operators will soon be able to buy a monitoring package or an analysis package. We’ve actually seen more interest in our product because [operators are] costconscious,” he continues.

Now business is good. Stueflotten cites “several good negotiations going on in the Norway and the UK,” and – perhaps nicest of all – “more and more operators are calling us,” he beams.

Leaving a trace Since last featuring in September 2014, UK-based Tracerco has continued to

expand its suite of chemical tracers for oil and gas. Research Chemist Aiden Brierley spoke to us about some of the company’s major developments over the past year.

Soluble tracers can be used to measure the movement of gas or liquid hydrocarbon phases in the well, while others can report on the effectiveness of frack water clean-out from each frack stage. Tracerco’s technology allows operators to measure which sections of an existing well are the most productive and reduce the amount of the unknown from future development, without the need for well intervention.

The value of this added information means that customer interest has remained very positive. Even in a tough market, Brierley says that demand has been high. He adds: “We’re continuing to develop new oil and gas tracers and we now have more than we ever had before.”

Despite a slump in the US market for many service suppliers, it continues to be a substantial part of the firm’s business.

Its footprint in the Middle East has grown, while unconventionals in Europe, Latin America and India has also meant healthy demand. In addition, he says that “work in China has been a fairly recent take-off. As their frack technology has come on line they’re starting to call on our services more and more.”

A key part of Tracerco’s strategy is NEWSBASE

that its research and its new products are all driven by customer needs. In one instance, this has involved improving tracer characteristics for specific well conditions such as HPHT, Brierley says.

“We have developed tracer suites which allow us to serve those wells at really high temperatures and pressures, reliably and robustly and with a really good analytical system that gives people peace of mind.”

Likewise, planning an enhanced oil recovery (EOR) strategy can also be improved via the application of tracer technology. “We have methods that allow us to quantify [residual oil] by injecting two different tracers and then track them across the field, and that gives you loads of information about the sweep of the field,” Brierley notes.

This has also led the company to set up five fully mobile laboratories. Based in a standard shipping containers, these contain the full range of equipment found in the company’s onshore labs, but can be deployed to wherever they are needed – even offshore. The result is that operators can receive tracer information and results in minutes rather than weeks.

All in all, it would seem that 2015 has been a successful year. “It’s a tough environment,” he says, “But we’re managing to still flourish in it – given the challenges we’re doing really well.” n

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November 2015

News in brief

New refineries key to Pertamina cutting fuel imports Pertamina expects its secondary refinery unit at Cilacap and the newly restarted Trans Pacific Petrochemical Indotama (TPPI) facility to cut annual imports of RON88 gasoline by up to 30%.

According to Reuters, the TPPI refinery in East Java will produce 61,000 barrels per day of the fuel, while Cilacap’s new residual fluid catalytic cracking (RFCC) unit will contribute an additional 30,000 bpd.

In an October 2 statement, Pertamina said the RFCC unit had started producing high-octane fuel on September 30, quickly reaching 70% of its initial production target of around 9,250 bpd.Pertamina also expects the RFCC to increase Cilacap’s LPG production to 1,066 tonnes per day, while also producing 430 tonnes per day in propylene products.

Cilicap is the largest refinery on the island of Java and had a total capacity of around 348,000 bpd prior to the US$1.4 billion

refinery upgrade delivered in partnership with Saudi Aramco.

The TPPI refinery first came on line in 1994, but has faced several threats of closure – most recently as the subject of a political corruption probe over condensate sales earlier this year.

Pertamina expects to restart the facility this month, with initial production slated at around 20,000 bpd. The company operates six refineries across Indonesia with a nameplate capacity of 1.04 million bpd.

But the ageing facilities often produce less, leaving the country heavily dependent on fuel imports to meet demand.

Pertamina’s US$25 billion refinery upgrade plan includes an overhaul of five facilities to increase production capacity and process more complex crude oil. At Cilacap, it is hoped the new RFCC unit will allow the production of fuels that meet the European Union’s Euro-4 quality specifications. Similar upgrades are anticipated to follow shortly at the Balongan and Balikpapan refineries, under partnership agreements signed with Aramco and China’s Sinopec in December 2014.

Pertamina’s chief, Dwi Soetjipto, has said he expects the upgrades to increase Pertamina’s actual refinery capacity from

NEWSBASE

around 820,000 bpd at present to 1.68 million bpd.

Edited by Andrew Kemp andrew.kemp@newsbase.com

API issues updated standards for shale development New editions of API’s hydraulic fracturing standards provide the latest technical direction for operators working to continuously improve well integrity, groundwater protection, and environmental safety. Last updated in 2011, API’s standards for shale development have worked alongside robust state regulations to ensure safe and responsible energy development with hydraulic fracturing for over 65 years.

“Hydraulic fracturing has unlocked vast energy resources, saving billions for consumers and putting America on a path to true energy security,” said API Director of

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News in brief

Standards David Miller. “Strong standards are key to America’s success as an energy leader, and that’s why we bring together regulators and operators to promote proven practices for environmental protection.

This update provides the latest guidance on equipment, monitoring, storage, and installation.”

Dubbed ANSI/API RP 100-1 and 100-2, the two new standards provide detailed specifications for pressure containment and well integrity, as well as environmental safeguards, including groundwater protection, waste management, emissions reduction, site planning, and worker training.

The release follows last year’s publication of ANSI/API Bulletin 100-3, which outlines community engagement guidelines to help operators communicate effectively with local residents and pursue mutual goals for community growth.

“Like all our guidelines on hydraulic fracturing, the new standards will be accessible to the public on our website and shared with regulators at every level of government,” said Miller. “Our voluntary standards serve as an important source of information for state regulators, who finalized an estimated 82 groundwaterrelated rules for oil and gas production, including hundreds of discrete rule changes, from 2009 to 2013 alone. As the EPA recently confirmed, these efforts have allowed America’s energy sector to achieve a track record of proven safety while growing our economy and cutting U.S. carbon emissions to near 27-year lows.”

API first began publishing standards in 1924 and currently has over 650 standards and technical publications. Over 100 of them have been incorporated into U.S. regulations, and they are the most widely-cited industry standards by international regulators. The program is accredited by the American National Standards Institute (ANSI), the same body that accredits programs at several national laboratories.

API is the only national trade association representing all facets of the oil and natural gas industry, which supports 9.8 million U.S. jobs and 8 percent of the U.S. economy.

API’s more than 625 members include large integrated companies, as well as exploration and production, refining, marketing, pipeline, and marine businesses, and service and supply firms. They provide most of the nation’s energy and are backed by a growing grassroots movement of more than 25 million Americans.

API

Aker Solutions wins deal for Malaysian deepwater project

Macgregor signs contract with Shunhai

NORWEGIAN service provider Aker Solutions has won a contract to deliver a subsea production system for US-based Murphy Oil’s Rotan deepwater gas field development in Malaysia.

The gas field, which was discovered in 2007, is located in Block H off Sabah. Aker Solutions announced the contract with Murphy Sabah Oil, a local subsidiary of Murphy Oil, on October 1.

According to Aker Solutions, the delivery includes hardware for four subsea wells, a hub manifold, in-line trees, a connection system and a production control system.

First deliveries are scheduled for the second quarter of 2016 and the contract will be booked as part of the company’s thirdquarter order intake.

“We’re very pleased to team up with Murphy on this important development,” Aker Solutions’ manager for Malaysia, Ravi Kashyap, said. “We look forward to continuing the good co-operation we’ve built over several years, having worked with Murphy on other projects in this strategically important region.”

Murphy Oil entered the Malaysian upstream in 1999 and currently holds majority interests in eight productionsharing contracts (PSCs) in the country, including the Block K PSC offshore Sabah as well as the Block H PSC. Block K has the Kikeh, Kakap and Siakap North fields. Aker Solutions has worked with Murphy in Block K, including on the Kikeh oil and gas project, the first deepwater development in Malaysia.

In early 2014, state-owned Petronas made a final investment decision (FID) on its second floating liquefied natural gas (FLNG) plant project, PFLNG 2.

The facility will be moored at the Rotan deepwater gas field and is designed to produce 1.5 million tonnes per year of LNG. It is scheduled to start operations in 2018.

Macgregor revealed last week that it had signed contracts with China’s Guangzhou Shunhai Shipyard for the delivery of special¬ised equipment. In a press release, the company, a subsidiary of Finland’s Cargotec, said it had agreed to supply the Chinese shipyard with six sets of deck machinery for installation on anchorhandling tug supply (AHTS) ships that are being constructed for an unnamed Middle Eastern client.

Specifically, it said it would provide anchor-handling/towing winch pack¬ages for five 48-metre AHTS vessels, each with 78-tonne bollard pulls, and one 40-metre vessel with a 70-tonne bollard pull.

“MacGregor will supply a mediumpressure 150-tonne capacity anchorhandling/towing winch, a tugger winch, capstan and hydraulic power unit for each of the 48-metre AHTS ves¬sels and a 100-tonne capacity anchor-handling/ towing winch, a tugger winch, capstan and hydraulic power unit for the 40-metre AHTS vessel,” the press release said. The order has been booked for intake in the third quarter of 2015.

The Cargotec subsidiary is due to send the first set of deck machinery to the shipyard in time to ensure that the first vessel is delivered to the unnamed client in December 2015. The remain¬ing ships are subsequently slated for completion at intervals ending in the third quarter of next year.

The value of the deal has not been disclosed, but Terry Onn, the Shiptype group sales manager for MacGregor’s offshore deck machinery division, said that the company had built on its successful record of co-operation with Guang¬zhou Shunhai.

“The yard already has experience of MacGregor’s high quality products, excellent project management, aftersales services and support, making it the obvious choice for these projects,” he added.

Guangzhou Shunhai’s client intends to use the AHTS ships for offshore towing operations and anchor handling in the Middle East.

Edited by Andrew Kemp andrew.kemp@newsbase.com

Edited by Andrew Kemp andrew.kemp@newsbase.com

NEWSBASE

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November 2015

News in brief

Iran and Norway deepen offshore ties NORWEGIAN government-backed trade body Intsok has signed a deal with Iran to increase co-operation in offshore projects.

According to a report by the Iran Daily newspaper Saeid Hafezi, CEO of the Iranian Offshore Oil Co. (IOOC) and Norway’s ambassador to Tehran, Aud Lise Norheim, reached the agreement last week. The meeting was also attended by representatives from Intsok, which aims to promote Norway’s oil and gas industry in international markets.

During the event, Hafezi said that he hoped that Norwegian companies would “soon have an active presence” in Iran’s oil industry.

“IOOC projects have great potential for bilateral co-operation. Norway is ready to raise mutual ties with Iran in all areas, especially in oil and gas projects,” added Norheim.

This move appears to make sense for Norway, whose oil and gas industry is likely to be affected by Iran’s return from international isolation following the recent nuclear agreement.

Oslo has been battling slowing production for some time as its mature fields decline.

Meanwhile, high costs – particularly in the Barents Sea region of the Arctic – are deterring investors as prices continue to remain depressed.

The prospect of a return to pre-sanctions levels of output from Tehran has raised fears that the cost of crude could fall further, placing more developments under threat.

Norway’s state-owned energy firm Statoil also has considerable experience in Iran. The company was involved in several phases of the South Pars gas field, before exiting in 2008 following the tightening of measures against the country. Statoil has also been previously singled out by Oil Minister Bijan Zangeneh as a company he would welcome back to Iran, along with other super-majors such as Total and Royal Dutch Shell.

For its part, Tehran will be hoping that it too can benefit from the sustainable development mantra practiced by the Norwegians, which has led to the country being revered by many as the blueprint for hydrocarbons exploitation.

Edited by Ryan Stevenson ryans@newsbase.com

DNV GL to lead project developing end of life guidance for offshore installations DNV GL, in collaboration with Decom North Sea (DNS), is seeking industry partners to participate in a joint industry project (JIP). The project will develop industry guidance to assist in effective and cost-efficient major accident hazard management for installations during latelife and end of life operations. It will also facilitate Safety Case compliance through cessation of production, well plug and abandonment, decommissioning, dismantlement and removal.

The JIP is in response to an industry request and reflects the importance of maintaining effective management of major accident hazards and legal compliance during the end of life phases of an installation. It also addresses the cost and effort required to deliver this; the recent significant revision of OSCR; and

Rig due for decommissioning anchored off the coast of Scotland

NEWSBASE

the lack of documented experience and practices.

The JIP will bring together key stakeholders including installation operators, supply chain organisations and regulators to develop a common understanding of the issues and current approaches. It will develop good practice guidance for effective and cost efficient major accident hazard management and OSCR compliance during the end of life phases of all installation types.

Participants of the JIP will be able to learn from others, share experiences, explore opportunities to reduce costs, and help shape fit-for purpose risk management and Safety Case compliance guidance.

This JIP should be of interest to: • Oil and gas installation operators/duty holders • Decommissioning/dismantlement turnkey contractors • Heavy lift vessel operators • HSE, DECC, MCA and other relevant regulators and authorities For further information about the JIP, contact Hamish Holt, Group Leader - SHE Risk Management DNV GL – Oil & Gas, UK and Sub Saharan Africa on +44 1224 335026 or e-mail hamish.holt@dnvgl.com DNV GL

November 2015

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News in brief

More Johan Sverdrup contracts announced STATOIL awarded more Johan Sverdrup contracts last week, demonstrating again what a lifeline the development is proving for North Sea contractors.

Dragados Offshore won a contract covering the engineering, fabrication and construction of a steel jacket for the field’s utility and accommodation platform.

It will be installed at Johan Sverdrup in summer 2018.

Kvaerner Verdal also won what is now its third contract for Johan Sverdrup. The latest, for the engineering, fabrication and construction of another steel jacket, is worth 1 billion Norwegian krone (US$120 million). The jacket, which will weigh 17,700 tonnes, will also be installed in summer 2018.

Kvaerner said that engineering would be performed at its offices in Oslo and would start immediately. Project management will be based at Kvaerner’s facility for complex jackets in Verdal.

Prefabrication and assembly will also start here from summer 2016. Kvaerner’s activity related to the contract will peak in the summer of 2017, when around 180 employees will be working on the project.

Contracts won for Johan Sverdrup so far guarantee Kvaerner “good activity” out to summer 2018, the company said.

Kvaerner is now delivering three of four jackets for the first phase of the Johan Sverdrup, said Kjetel Digre, senior vice president for Johan Sverdrup.

“Having documented learning and synergies in connection with existing contracts, Kvaerner … will contribute to improved competitiveness and maximised value creation from Johan Sverdrup,” he added. The first phase of Johan Sverdrup will consist of four installations, including a utility and accommodation platform, a processing platform, a drilling platform and a riser platform, as well as three subsea water injection templates.

Investment costs for the first phase are anticipated to total around 117 billion krone (US$14.33 billion).

Recoverable resources at Johan Sverdrup, which is aiming for a 70% recovery rate, are projected to range from

1.4 billion to 2.4 billion barrels of oil equivalent. Statoil is the operator of Johan Sverdrup with a 40.02% interest. Lundin Norway holds a 22.6% stake, while Petoro owns 17.36%, Det norske oljeselskap holds 11.5% and Maersk Oil has 8.44%.

Edited by Ryan Stevenson ryans@newsbase.com

TMK expects flat demand for pipes next year RUSSIA’S TMK has said it expects global demand for oil and gas pipes to remain stagnant throughout next year, at best seeing a modest rise of up to 2% compared to this year.

The world’s largest producer of steel pipes for the energy sector also said on October 19 that demand this year would likely fall 13-15% compared to 2014, and would only see a recovery in 2016 if oil prices hit US$60 per barrel.

Low crude prices have prompted oil and gas companies across the world to cut spending, which has had a knock-on effect on the oil service and equipment manufacturing industry.

TMK shipped 2.93 million tonnes of steel pipe during the first nine months of the year, down 7.1% from the same period in 2014.

The firm blamed the fall on weaker sales from its American Division, whereas demand in Russia remained steady, with shipments growing 9% over the same interval.

Drilling activity in the Russian market rose 7% this year, with oil production growing by 1.5%. Russia is TMK’s core market, accounting for 65-70% of its total sales.

“Oil production is growing in Russia, growing in OPEC countries, and after the lifting of Iran sanctions there will be again some increase,” TMK chairman Dmitry Pumpyansky told Reuters, “[But] oil production in 2016 could continue to slide in the US, in Canada, and there’s huge political risks in the Middle East, so our forecast is production of oil will be flat next year.”

TMK has seen upsides and downsides to the weakening rouble, as the company prepares to convert debt currently held in rubles into the US dollar.

It expects up to 50% of its debt to be denominated in rubles next year, compared NEWSBASE

with around 31% presently. “In the case of the debt portfolio [the ruble depreciation] is positive, but generally it’s not positive,” said Pumpyansky, “In the first six months our EBITDA in the Russian division rose up to 70% in rubles; in dollars it [rose] about 8%.”

In addition to the US and Russia, TMK’s main markets include the Middle East, Europe, North Africa, South and Southeast Asia and the CIS. Edited by Joe Murphy joem@newsbase.com

Aker Solutions and MAN Diesel & Turbo form subsea compression alliance Aker Solutions and MAN Diesel & Turbo agreed to form an alliance to develop the next generation in subsea compression systems that can be used at even the smallest oil and gas fields to increase recovery and lower costs compared with conventional platform solutions.

The two companies will build on their experience and cooperation from the successful delivery of the world’s first fullscale subsea gas compression system at the Åsgard field in Norway. A key objective of the partnership is to develop new, costeffective technology for high-capacity subsea compression systems. “Åsgard was a game-changer that moved compressors from platforms to the seafloor to improve recovery rates, reduce costs and enhance safety,” said Alan Brunnen, head of Aker Solutions’ subsea business. “We’re taking the technology further to provide compression systems that are smaller, lighter and cheaper without compromising on effectiveness.”

The alliance combines Aker Solutions’ capabilities in subsea processing, compression systems, controls, systems and interventions with MAN Diesel & Turbo’s leading turbomachinery technology and its extensive gas compression expertise. The compression systems will be based on proven technology and for use at small subsea fields as well as large deposits such as Åsgard.

AKER SOLUTIONS

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November 2015

News in brief

Shipbuilders chase floating opportunities Asi an shipbuilders are seeking to cash in on surging demand for small- to mid-size floating storage and regasification units (FSRUs), which developers are turning to as a cost-effective alternative to onshore plants.

FSRUs cost around US$300 million to build – around half as much as an onshore import terminal – and can be up and running as much as six times faster.

They therefore offer emerging countries an effective way to tackle power shortages by importing LNG. There are already 20 FSRUs installed around the world and demand is growing fast. Indonesia, for example, plans to develop small-scale regasification and power plant infrastructure at 32 locations.

In terms of demand for FSRUs, “the main driver is speed,” said Hoegh LNG CEO’s, Sveinung Stohle. “Demand for FSRUs follows a drastic reduction in the cost of LNG. We see that this has caused a very strong increase in requests.” Shipyards in South Korea and Singapore have been quick to respond with new proprietary technology aimed at cutting costs.

Daewoo Shipbuilding & Marine Engineering (DSME), for example, has completed the conceptual and basic design for a floating storage power plant (FSPP) capable of generating 200 MW. It is working to win more orders to manufacture its proprietary LNG-fuelling systems, according to its general manager of product strategy, Stephano Heo. Hanjin Heavy Industries & Construction (HHIC) is also reviewing small-scale FSRU designs with storage of up to 25,000 cubic metres to meet demand for countries such as Indonesia, said the company’s senior principal of design engineering, Lee KiChoon.

The shipbuilder has developed a new FSRU design and is considering both open and closedloop heating systems for intermediate fluid vaporisers. It has also developed a design for a smaller, 14,000 cubic metre FSRU, he said.

Samsung Heavy Industries has designed a midscale FSRU and power plant with storage capacity of 80,000 to 100,000 cubic metres but says it will probably remain selective about any FSRU orders it chases.

This is largely because its yard in Geoje has

already landed a raft of contracts to build floating LNG (FLNG) facilities, so it is close to capacity.

Singapore’s SembCorp Marine has developed a scalable, module concept that can be extended across regasification, power generation and LNG bunkering operations and aims to offer an integrated regasification alternative to FSRUs. Competition to supply FSRUs has meanwhile cut the cost of leasing such vessels by 20% from five years ago to around US$120,000 per day, according to Keith Bainbridge, the managing director of industry consultant CS LNG. Edited by Ed Reed edreed@newsbase.com

New well confirms Libra potential A fourth well in the Libra area “confirms the potential” of the pre-salt block offshore Brazil, state-run operator Petrobras said last week.

Well 3-BRSA-1310-RJS is the fourth to have been drilled in the area and has identified the presence of hydrocarbons in what the driller described as “a lowporosity reservoir” located in the central portion of the block, which is in the Santos Basin. The company said the well’s results would help provide “important information for the ongoing appraisal campaign of this structure”. Drilling is also under way at two other locations in the block. Well 3-RJS-739A in the northwest area of the block has already found carbonate reservoirs with oil and is undergoing coring operations to collect reservoir samples. In the north of the block drilling of well 3-RJS-741 has just begun.

Potentially one of the biggest oil finds in the Americas in recent decades, the Libra’s consortium has already hired a floating, production, storage and offloading (FPSO) vessel with capacity to produce 50,000 barrels per day of oil and 4 million cubic metres of natural gas daily for deployment in extended well tests. Another larger FPSO with a capacity of 180,000 bpd of oil and 12 mcm per day of gas is being tendered for the Libra Pilot Project.

The Libra consortium is made up of operator Petrobras with a 40% stake, Royal Dutch Shell and Total with 20% each and NEWSBASE

Chinese state oil companies CNPC and CNOOC with 10% each.

The group won the block in an auction in 2013 with the sole bid at the minimum price First oil from the area is now not expected until the first quarter of 2017, according to Odebrecht Oil & Gas, which is joint operator of the platform that will carry out the first long duration test. Previous guidance from Petrobras had the second half of 2016 as the target.

With up to 12 billion barrels of recoverable oil, developing the pre-salt field is central to Petrobras’ revised business plan. It focuses on pre-salt development as a means of rescuing the company from the financial wreckage caused by corruption and poor management, which has been exacerbated by the drop in the oil price.

Libra was the first block to be auctioned off under Brazil’s controversial new production- sharing agreement (PSA) legislation that gives a central role to new state oil company Pre-Sal Petroleo in its development.

Edited by Ryan Stevenson ryans@newsbase.com

Marcellus output slows amid pipeline bottlenecks Some natural gas producers operating in the Marcellus shale are reportedly being forced to choke back output owing to a lack of pipeline capacity, with overall volumes now set to drop below levels recorded last year.

According to the latest Drilling Productivity Report from the US Energy Information Administration (EIA), output for November from the region could fall to 15.699 billion cubic feet (444.6 million cubic metres) per day from 15.892 bcf (450.1 mcm) per day in the same month of 2014.

This comes as production from the play, which is the US’ largest natural gas reservoir, continues to outstrip pipeline capacity despite new capacity coming on line this year. This is putting further pressure on margins that are already extremely slim.

Earlier this month, Stone Energy announced that it had shut in its Mary field in the Marcellus, cutting the company’s production by roughly 100-110 million

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News in brief

cubic feet (2.8-3.1 mcm) per day. This, it added, was owing to “the low margins in Appalachia”.

Speaking to Bloomberg in October, a BNEF analyst, Charles Blanchard, said other producers were “saying it’s not even worth it day to day” to keep wells on line, as they are “losing money on every molecule” that they sell.

A number of new pipelines are under development in an attempt to resolve the bottlenecks. These included the proposed 1 bcf (28.3 mcm) per day PennEast Pipeline, which would supply gas from the eastern Marcellus to Pennsylvania and New Jersey.

The project is already nearly fully subscribed, with 12 buyers in place for 90% of its firm capacity.

“New pipeline capacity like that of PennEast is the key to unlocking the competitive advantage of abundant Pennsylvania natural gas,” the Pennsylvania Manufacturers Association’s president, David Taylor, said recently.

Edited by Anna Kachkova annak@newsbase.com

Chevron continues Big Foot investigation Chevron’s Big Foot platform has been returned to Kiewit Offshore Services’ facility in Ingleside, Texas, as the super-major continues to investigate the failure of tendons designed to anchor the platform in the US Gulf of Mexico earlier this year.

Nine of the 16 tendons lost buoyancy and sank in June. The platform was not connected to any wells or tendons at the time of the incident and sustained no damage, but was moved to sheltered waters. The company has now confirmed that the tension leg platform (TLP) arrived at the Kiewit facility in early September.

“The investigation into the incident is ongoing,” Chevron was reported as telling FuelFix in a statement this week. “As we complete the investigation and update our plan we will be in a better position to provide an update.”

The Big Foot project had already been stalled for months before the incident because of strong loop currents in the Gulf, which had forced Chevron to delay towing

the platform to the Walker Ridge area.

Now there is speculation that the same loop currents may have caused the tendons to fail.

The tendons were fabricated by Kiewit and installed by Heerema Marine Contractors. Each tendon is around 1 mile (1.6 km) long and is designed to help keep the TLP tethered to the seafloor.

Big Foot has a design capacity of 75,000 barrels per day of crude and 25 million cubic feet (708,000 cubic metres) per day of natural gas.

In March, Chevron had towed the TLP to Walker Ridge Block 29, around 225 miles (362 km) south of New Orleans, Louisiana, where it planned to install it in roughly 5,200 feet (1,585 metres) of water.

Production was anticipated to begin from Big Foot in 2016, but after the incident, Chevron said it did not expect any output from the project in 2016 or 2017.

Edited by Anna Kachkova annak@newsbase.com

Three in running for Kuwait TSAs The field of international oil companies (IOCs) negotiating new technical service deals covering some of the country’s most valuable acreage has narrowed to three. The CEO of state-owned Kuwait Petroleum Corp. (KPC) Nizar Adsani made the announcement in early October while adding that the agreements were targeted for signature by the end of the year.

His counterpart at upstream subsidiary Kuwait Oil Co. (KOC) pledged this time last year that the first of the mooted deals would be concluded by the end of the second quarter of 2015 without result, but the closure since May of both producing fields in the Partitioned Neutral Zone (PNZ) appears to have galvanised upstream development activity and bids are due later this month for contracts to work on the northern Jurassic fields.

Addressing a conference in Kuwait on October 12, Oil Minister Ali al-Omair insisted that the government remained committed to raising capacity to 4 million barrels per day by 2020 despite current global oversupply concerns – and despite widespread scepticism over the timetable’s achievability given long project delays.

According to Adsani, discussions are under way with super-majors BP, Royal Dutch Shell and Total on technical service NEWSBASE

agreements (TSAs) covering Greater Burgan in the south east, areas in north Kuwait, and heavy oil formations in an unspecified location – without indicating which company was interested in which contract area.

Formal tenders would be issued later this month with awards due by the end of the year, he said. Speaking in October 2014, KOC’s Hashem Hashem claimed that five firms – then including US giants Chevron and ExxonMobil – had been invited to bid for the first of the three contracts, involving heavy oil. But he expressed doubt at the time that Exxon would table an offer while relations with Chevron have since soured over joint operations in the PNZ. All three of the remaining prospective bidders have experience of working under some form of TSA with KOC. Shell has conducted extensive studies in the north, although these have focussed more heavily on possible sour gas reserves, while BP signed a TSA in September 2014 to assist with enhanced oil recovery (EOR) at the Burgan field.

Of more immediate likely impact on production will be the award of three contracts tendered in August among fourteen prequalified bidders to develop Jurassic reserves at the East Raudhatain, West Raudhatain, West Sabriya and Umm Niqa fields in the northeast.

Bids are due on October 27, with each package entailing adding production of 40,000 bpd. Contracts aimed at developing a further 150,000 bpd of capacity are due to be tendered early next year. Adsani also reaffirmed claims by other industry officials that drilling work was intensifying, predicting a rise in the rig count to 140 by the end of 2016 from around 90 at present.

Both he and his recent nemesis Al-Omair were also bullish on prospective near-term output increases – which would go some way to compensating for the loss of around 250,000 bpd of equity production from the PNZ’s two producing fields, Khafji and Wafra.

Putting current capacity at 3.2 million bpd and production at 2.95 million bpd, Adsani projected a 200,000 bpd increase by the end of 2016, while Al-Omair agreed on current output and forecast an increase to above 3 million bpd during the first quarter of 2016.

OPEC’s latest monthly report puts Kuwait’s September production at 2.7 million bpd, based on secondary sources. n Edited by Ian Simm ians@newsbase.com

page 36

InnovOil

November 2015

Moving on UPPP

As more companies puzzle over how to attract new and young talent, MOL Group is using innovative online gaming platforms to spark students’ interest in E&P

D

espite other urgent matters weighing more heavily on oil and gas, the issue of recruitment and personnel replacement burns quietly in the background. The so-called Big Crew Change – the widespread retirement of a generation of skilled and experienced oil workers – means that the industry is now adopting some new and highly innovative recruitment strategies to engage today’s school students and graduates.

In October, Budapest-headquartered MOL Group concluded the intake of its exploration & production competition, UPPP. Competing to win a prize pot of 25,000 euros and a technical placement (or summer internship for undergraduates, the programme begins with online virtual simulation, where teams must solve challenges based on real-life E&P and industrial problems. The winning 10 teams proceed to a live Grand Final, where they again compete to solve more challenges, and must present their exploration findings to a number of MOL Group’s senior board.

One of the most innovative aspects of

the process is what MOL Group HR vice president Zdravka Demeter Bubalo calls the “gamification platform” – the virtual online challenges based on simulations of real E&P work. “We did it because we recognised the importance of challenging the traditional way of hiring, and we wanted to offer a unique approach to support talent development and keep our MOL Group colleagues better engaged,” she explains.

InnovOil spoke with Bubalo and her team just as entries closed on this year’s UPPP intake. In just a few weeks, 1,112 three-person teams from 50 countries registered to take part, showing impressive growth on the programme’s successful launch in 2014. “Last year we started with 27 universities in 14 countries, but this year we opened it up to teams worldwide,” she continues.

With interest growing, the scheme also supports international teams – another way in which it can mirror the real-life element of working E&P departments “Competitors are working internationally,” Zdravka says, “And this year we offered the possibility of NEWSBASE

a crew finder so they can find teammates from other countries, and this really supports the global mindset.”

These teams will now compete until November 6, before winners are chosen for the live 3-day final, taking place December 8 and 9 in Budapest.

Freshhh approach This is an approach which the group is using not just as a recruitment tool, but as a way of encouraging interest at all levels of education. “Fewer students are enrolling in natural sciences and STEM subjects these days,” Bubalo says. “We wanted to take a unique approach in terms of gamification, to attract them to natural sciences in general – and we’re doing this with our Junior Freshhh competition in secondary schools.”

The UPPP programme supports MOL’s two other talent streams – Freshhh and Growww. Freshhh aims to widen the scope of entrants and is open to students studying any degree subjects; Growww is the company’s graduate recruitment programme, which, since its inception in 2007, has taken on 1,570 graduates.

November 2015

InnovOil

page 37

The MOL Group UPPP program top ten teams

The MOL Group UPPP program winning team: ONIONGAS from Poland These too are expanding, with a view to drawing students in to STEM subjects at a younger age, Bubalo explains. “We’re putting additional efforts into our Junior Freshhh competition, where we provide a platform for young secondary school students to get interested in maths and physics.”

For older students, the UPPP and Freshhh programmes have offered very valuable context and experience for students, especially in the more academic environments of STEM subjects. By blending “game” elements, which provide quick tests and challenges, with the onthe-job training inherent in the corporate placements, the programmes offer students a fairly broad scope of the E&P landscape. “What we’ve seen with STEM students is that they do not often have a chance to work on real-life challenges,

especially in E&P – this gives a good blend of gamification and later on, real-life experiences as well.”

The outcome has been very effective in terms of corporate staffing and candidate selection. “We have a high retention rate on Freshhh and Growww, more than 80%,” Bubalo says. “Since 2007 we have an extreme retention rate and within this time almost 40% have already been promoted to managerial positions.”

Media reaction What has been interesting for MOL Group is the extent to which programmes like UPPP can generate responses from their contestants into the wider world – increasingly a vital tool not only of recruiters, but for major operators in general. “We are amazed how active they are on Facebook and on the [UPPP] NEWSBASE

application platform. The social media platform is the one which brings them all together no matter where the borders are,” Bubalo enthuses.

Looking ahead, Bubalo sees the potential in adapting these competitions in line with the future of MOL’s business – running dedicated offshore or disciplinary schemes, for example. “I believe we will go in line with our strategic direction in E&P. Currently we are strong in Central and Eastern Europe, but in future we might look more to offshore and North Sea, so we might look to tailor the competition.”

Either way, all of MOL’s efforts mark a distinct change in an industry only just acknowledging that it has to adapt to attract new talent. “Not only depending on the market, but I believe that our industry should be more innovative for the general interest of our children,” Bubalo notes.

“What we’re seeing in the HR arena of E&P is that people are thinking more and more about innovative approaches.”

The advent of digital technology can go some way towards helping students engage too. Virtual systems such as Oculus Rift, as well as the industry’s powerful simulation and modelling tools, can not only help the industry train its existing members, but can also be a powerful method of encouraging engagement early on.

With companies like MOL leading the charge, programmes such as UPPP may well become more common as the sector continues its efforts to attract the world’s best and brightest. n

page 38

InnovOil

November 2015

What next …?

To make enquiries about any of the products or technologies featured in this edition, use this list of vital connections If you would like to learn more about FoundOcean’s strategy for keeping offshore operations efficient, contact Alexandra Leo on +44 (0)1628 567 000 or Alexandra.Leo@Foundocean.com For more information on Siemens’ SST-600 oil-free stream turbine, please speak to Kerstin Schirmer via kerstin.schirmer@siemens.com To make further enquiries about Weatherford’s TruFrac® composite frac plug, please contact Sandra Pham at Sandra.Pham@Weatherford.com If you are interested in attending the European Shale Gas and Oil Summit 2016, or would like to know more, contact Callum Flynn on +44 (0)151 230 2110 or email callum.flynn@charlesmaxwell.co.uk If Primus Green Energy’s GTL solutions could help you recapture some of the lost value in flared gas, contact Jerry Schranz on +1 201 465 8020 or email jschranz@antennagroup.com For more information on MOL Group’s UPPP programme, or about its range of education and graduate schemes, contact Kathryn Williams at k.williams@bcmpublicrelations.com If you’d like to know more about Falcon Oil & Gas or its exploration programme, contact Georgia Mann at georgia.mann@camarco.co.uk If Tracerco’s innovative oil and gas tracers could be of use in your oilfield, speak to Helena Barras at Helena.Barras@tracerco.com To learn more about the Turborunner or for more information on Deep Casing Tools, contact Avril Carruthers at Avril@deepcasingtools.com To make an enquiry about Geomec’s well monitoring software , Jarle Steen Stueflotten can be reached at jarle@geomec.com

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

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

“We were pleased

immediate interest that our article attracted.”

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

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