InnovOil Issue 35 July 2015

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Bringing you the latest innovations in exploration, production and refining Issue 35

July 2015

Longer shelf life

How EOR is helping Statoil reach 60% recovery Page 12

Nailing down Hammerhead™ A closer look at Baker Hughes’ ultradeepwater completion system Page 9

Going for GLORI The proven potential of microbial EOR Page 14

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July 2015

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

Russian sanctions

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Hammerhead™ 9 New equipment for ultradeepwater completions

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

EOR Special Supplement Extending shelf life

12

The power and the Glori

14

Back CO2 for the future

18

Attracting Attension

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Statoil’s Dr Øivind Fevang discusses ambitious recovery goals and what part EOR has to play in achieving them

Media Sales Manager Gary Paterson garyp@InnovOil.co.uk Design & Web Dan Bell Danielb@newsbase.com

Glori Energy’s microbial EOR technology changes the fortunes of mature fields

Editor Andrew Dykes andrewd@newsbase.com

Deploying CO2-EOR in the UK and Norwegian North Sea

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The Attension High Pressure Chamber from Biolin Scientific

New orders from Captain 21

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Jee awarded a FEED contract at North Sea’s Captain EOR project

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Subsea water injection

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Looking into the IRIS

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The Spirit of the age

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SWIT™ technology from NOV/Seabox

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Researching EOR with industry, universities and government

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ations Bringing you the latest innov

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State-run agencies are forming joint ventures with the aim of expanding the capabilities of domestic suppliers

Associate Director of Business Development Andrew Stalker andrews@newsbase.com

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A note from the Editor

and refining in exploration, production

July 2015

Issue 35

DSME’s latest state-of-the-art and super-efficient LNG carrier

f Life Longer sheLStatoil reach 60% recovery How EOR is helping Page 12

™ n hammerhead naiLing dow epwater at Baker Hughes’ ultrade A closer look completion system

Decommissioning costs 30

Page 9

The firms stepping up to the challenge

Speeding up inspections 32 The Magna Subsea Inspection System™ gLori going forntial of The proven pote microbial EOR Page 14

News in brief

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Contacts 41

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A note from the Editor While preparing this month’s enhanced oil recovery (EOR) edition, I spoke to a number of companies and researchers throughout the IOR/ EOR sector and across the globe.

As with many challenges the industry faces, the ways in which the issue is approached are enormously diverse. While the problem of declining production and maturing fields remains much the same across the board, the strategies for improving this are almost always unique to each field. This means that even as the subsea and topside construction industry pushes for more standardisation and the goal of “plug and play” equipment, EOR solutions are increasingly bespoke as understanding grows.

Moreover, to implement EOR techniques successfully – as research directors of the International Research Institute of Stavanger (IRIS) comment later in this edition – we must also go back to basics to make sure we understand the fundamentals of how reservoirs and enhanced production techniques behave. A better understanding of the inner workings of latelife fields – and where water, polymers, gas or other substances will flow inside them when injected – will go a long way towards making EOR technologies more effective.

With this in mind, Statoil’s chief researcher for petroleum technology, Dr Øivind Fevang, discusses the company’s ambitious recovery goals, and how EOR is aiding their achievement. In particular, he comments on how EOR techniques are now being incorporated into the company’s strategy from the very beginning of development. Polymer

injection is already being trialled to release the heavy oil deposits of Norway’s newest giant field, Johan Sverdrup.

This edition features all of the aforementioned technologies, from more versatile water injection via Seabox’s SWIT™ unit, to Glori energy’s revolutionary take on microbial EOR (MEOR), to SCCS’ report on the potential gains of a North Seawide effort for CO2 injection.

Biolin Scientific also profiles the Attension High Pressure Chamber, a new addition to its Theta tensiometer range, which can better simulate the high pressure and high temperatures of oil reservoirs needed to study wettability more accurately.

Outside the realms of EOR, we also feature new innovations from Baker Hughes and Oceaneering, as well as a look at Daewoo Shipbuilding & Marine Engineering’s latest, super-efficient LNG carrier, the Creole Spirit.

Meanwhile, Vladimir Kovalev reports on Russia’s efforts to reduce its reliance on foreign technology and innovate within its borders. Two new joint ventures have been launched with the aim of developing new technology for the country’s oil and gas industry.

We also examine the new products and services already aiming to lower the looming cost of decommissioning.

Finally, as many EU and US firms wind down for the quieter summer period, all that remains is to wish our readers pleasant holidays and vacations, wherever they may take them.

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

Andrew Dykes Editor

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InnovOil

July 2015

COMMENTARY

Russia reacts to service sector sanctions Vladimir Kovalev reports on two state-run agencies which are now forming joint ventures with the aim of expanding the capabilities of domestic suppliers of equipment and technology

S

anctions mean Russia is under pressure to source its own machinery.

Now, manufacturers and geological survey firms are considering the establishment of at least two major ventures, as the government looks to reduce national dependence on foreign suppliers of oil and gas equipment and technology. Moscow is keen to give domestic service companies an edge over their international competitors in light of the sanctions introduced by the European Union and the US last year.

State-controlled RosTech has already pressed ahead on this front by forming a joint-stock company with Unified Heavy Machinery Corp. (OMK), whose major partners include Rosneft, Rusal and other big domestic firms. This is the first step towards the creation of a larger entity that will be capable of providing a wide range of equipment to replace the foreign supplies that are now out of reach.

RosGeologia, the state-controlled geological research operator, is looking into a similar plan. It hopes to organise a new structure to enable the development of technologies used in geological research.

Russian equipment producers and service companies have faced strong competition from foreign providers in recent years.

Yet given the current conditions, the Kremlin is keen to improve the quality and technological capabilities of domestic companies in order to ensure the stable functioning of the oil and gas sector.

OMK-Neftegaz The new joint-stock company created by RosTech and OMK will be known as OMKNeftegaz. It was officially registered on February 17 and is a 50/50 venture between a RosTech subsidiary, RT Global Resources and OMK. OMK-Neftegaz is slated to invest up to 20 billion rubles (US$376.3 million) to establish new production lines for equipment used in the oil and gas sector, as well as other engineering solutions and software. By beginning of 2016, it intends to take control of a number of plants in the Tula, Tver, Yaroslavl, Volgograd, Ryazan and Perm regions, as well as the Krasnodar territory and the republic of Bashkortostan.

According to RosTech, the venture will allocate 10 billion rubles (US$188 million) to buy stakes in these plants, to acquire modern technologies and to localise production processes, all of which will be financed via share issues.

OMK and RosTech hope that the company will begin commercial operations in 2020 – and their ambitions are lofty. By this time, they believe the new firm will be able to acquire a 20% share of the national market and earn a profit of 36 billion rubles per year (US$677 million).

Sanctions and subsidies RosTech’s ambitious plans stem from Moscow’s concerns over the second wave of Western sanctions imposed last year.

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The first wave of trade restrictions mostly targeted the oil industry, with a special focus on the exploration and development of new offshore crude deposits. At the time, EU officials stressed that the sanctions regime would not affect deliveries of natural gas, since Europe was heavily dependent on Russian supplies of that commodity.

The second wave could have an effect on deliveries of other types of equipment for gas production. This is a concern for the Kremlin, especially since the sanctions regime has so far had more of an impact on the oil sector than the gas industry.

Despite the supply restrictions, the Russian government indicated in March of this year that it expected domestic and foreign companies to invest about US$5 billion in the development of the country’s oil and gas heavy machinery production lines over the next five years. Western firms will not be involved, since they have been barred from developing or delivering high-tech production equipment in Russia.

However, Moscow is likely to invite major operators based in Asian countries, particularly China, to play a role.

The Kremlin will probably seek to attract Asian investors that can finance their own contributions to new import-substitution projects. This will be a key consideration, given that the Western sanctions regime also restricts state-controlled Russian holdings’ access to capital markets.

Industry and Trade Minister Denis

July 2015 2015

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COMMENTARY Oil field in Eastern Siberia

Mantrurov recently stressed this point, saying: “By 2020, Russian and international companies will have to invest more than US$5 billion in the oil and gas machinery construction sector. For this reason, we should maintain a position of not limiting the participation of international companies.”

The Kremlin hopes to maximise the growth of the domestic oilfield services sector and is working to expand the use of locally sourced equipment and technologies to the greatest extent possible, Mantrurov said. However, this will not be easy to achieve, he acknowledged. “Unfortunately, international companies are not actively going for it.”

In the meantime, he said, the government anticipates that it will be able to provide 10-15 billion rubles (US$188-282 million) worth of support for the development of the oil and gas heavy machinery sector by 2030.

Moscow will disburse about 4 billion rubles (US$75 million) of this over the next five years, he added.

The view from Parliament The Kremlin’s position has found support in Parliament.

Vyacheslav Tetyokin, a member of the State Duma representing the oil-rich Tyumen region and Khanty-Mansi autonomous area, recently pointed out that Russian oil and gas firms remained highly reliant on foreign contractors, especially for

services. Before the imposition of sanctions, he said, this area of operations was dominated by Western companies such as Schlumberger and Halliburton, despite the fact that there are more than 200 domestic providers in existence.

Foreign companies have attained an overall market share of 40% or more, Tetyokin said, because of their “increasing technical advantage” over local competitors.

Russia’s integration into the world economy has also played a role, he argued.

“Currently, there is an unhealthy situation in the market for oil and gas services, which is reflected in the monopoly of Western corporations that has increased with Russia’s entry into the WTO [World Trade Organisation],” he said. “Such companies dictate prices, crowding out Russian producers, saving on Russian labour, limiting access to technologies and not infrequently using offshore financing sources.”

Local providers simply cannot compete effectively in the current climate, he asserted. “Subsidiaries of our oil companies are bound to participate in competitions and tenders on equal terms.

However the victory, as a rule, sails away, because ... Schlumberger, Baker Hughes and Halliburton offer more favourable conditions. These transnational corporations have at their disposal [larger] financial resources and, more importantly, technological resources than we can dream of,” he remarked.

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Dependence on imports is believed to be even stronger in the realm of geological research. In this sector, foreign equipment accounts for up to 75% of the equipment used by exploration enterprises for onshore projects and around 90% of equipment for offshore initiatives.

Stumbling block According to Mantrurov, the Russian government is working to correct the situation by drawing up a set of 20 plans for import substitution in key sectors of the economy, including oil and gas services and equipment. Moscow will also introduce local-content requirements for Russian energy companies, he said.

But these ambitious plans may be stymied by bureaucratic complications.

This is hardly surprising, given the red tape that goes along with projects involving huge state-controlled structures such as RosTech.

As a result, even though the government sees the establishment of a unified megaholding such as OMK-Neftegaz as a means of ensuring the efficient management of different projects, the service sector could easily end up drowning in red tape. If the new joint-stock company has a large number of different departments and a complex organisational structure, it will have difficulty achieving its objective of giving a boost to domestic equipment and technology providers. n

July 2015

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Baker Hughes’ Hammerhead™ circles the Gulf of Mexico As explorers push into the Gulf of Mexico’s Lower Tertiary play, new equipment such as Baker Hughes’ Hammerhead™ is pushing the envelope of what is technically possible

T

he industry’s push towards harsher, more challenging production frontiers is a well-covered narrative.

But with deepwater production well into its second decade, it is perhaps easy to forget that there are deeper prizes still.

Developing the Lower Tertiary in the Gulf of Mexico, described a few years ago by some enthusiastic observers a “gold rush,” may be less appealing at today’s prices – but it will happen. Yet tapping the potential 14-40 billion barrels in the ultradeepwater Paleogene play is still at the edge of technological feasibility.

Even as recently as 2012, BP’s executive vice president Bernard Looney remarked that some of its prospects “lie beyond our industry’s current limit of 15,000 psi and 275°F [135°C].” But now the industry’s biggest players are beginning to bring their latest innovations to market, designed specifically to tackle the region’s Herculean requirements.

Baker Hughes’ Hammerhead™ system has been built for this very task. The brainchild of the services giant’s Lower Tertiary Integrated Project Team, set up in 2012, the result is a “a built-for-purpose, integrated completion and production solution,” for use in high-pressure/hightemperature (HPHT) ultra-deepwater reservoirs.

What lies beneath According to Baker Hughes, Hammerhead is designed for use at total well depth of up to 33,000 feet (10,000 metres), in 10,000 feet (3,000m) of water. Here the system works at pressures of up to 25,000 psi (1,724 bar) and temperatures up to 150°C. Fully assembled, the comprehensive high pressure high temperature Hammerhead system includes an upper completion with intelligent well system (IWS) capabilities that allow remote monitoring; an isolation assembly that provides well control during installation of upper completion, and a single trip multizone lower completion system.

Hammerhead Ultradeepwater Integrated Completion and Production System

The lower completion provides a 5.25inch (133-mm) minimum production inside diameter, the largest on the market for a high pressure 8.5-inch (216-mm) drift completion. This allows the system to handle sustained flow rates of up to 30,000 barrels per day, at differential pressures of up to 15,000 psi (1,034 bar).

The system’s lower completion includes screens, sleeves and packers and is run in a single trip. In addition, it includes a fracpack system capable of working under the extreme pressures, rates and temperatures of the Lower Tertiary. Provided operations can be aided by advanced stimulation vessels, this can deliver up to 5 million lbs (2.26 million kg) of proppant at rates of up to 50 barrels per minute, and into as many as five zones.

Once in place, monitoring equipment such as fibre-optic cables and pressure NEWSBASE

sensors inside the lower completion can be brought on line via downhole wet-mate technology, allowing operators to monitor pressure and temperature. This “continuous stream of real-time data allows for 24-hour surveillance,” ensuring safety and reliability throughout a 20-year production life.

Technologies like Hammerhead will be needed if operators are to make good on the promise of the Lower Tertiary. At present, average recovery factors here sit at around 6% or less, but the company is confident that Hammerhead will be able to improve recovery factors by 2%.

As its president of global products and services, Richard Ward wrote in a recent FuelFix blog post, ”For every 1% increase in reserves that can be recovered from the Lower Tertiary, operators will be able to increase revenues by approximately US$2 billion at US$50 oil.” n

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InnovOil

July 2015

EOR

Special supplement Pages 11-26

What’s in the box?

Seabox’s versatile subsea SWIT™ system could revolutionise water injection Page 22

Capturing imaginations CCS and CO2–EOR could unlock millions of extra barrels – if we act now Page 18

Under pressure

Biolin Scientific’s Attension High Pressure Chamber helps measure wettability Page 20

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July 2015

EOR special supplement

Statoil: Extending shelf-life with EOR Statoil’s chief researcher for petroleum technology, Dr Øivind Fevang, discusses the company’s ambitious recovery goals and what part EOR has to play in achieving them

“We are constantly looking for any potential game-changer within the entire IOR value chain.

In 2014 we opened a new IOR laboratory focusing on fundamental understanding and developing new IOR technologies.”

Dr Øivind Fevang

Above right: 4-D seismic monitoring at Snorre and Grane

D

r Øivind Fevang has an exciting, if perhaps unenviable, job.

As Statoil’s chief researcher for petroleum technology, he aligns Statoil’s R&D portfolio, with the demands of the company’s business units and production licences.

It involves finding solutions to the myriad challenges of the company’s diverse operating regions, from new fields within the Arctic Circle to the offshore heavy oil development in Brazil and the tight oil in the US’ shale plays. Closer to home, work on the Norwegian Continental Shelf (NCS) poses some interesting complexities: although many producing assets are now reaching late life, Statoil is also bringing new field development projects on line.

Statoil has an ambitious target of reaching an average of 60% recovery on its operated licences on the NCS. Reaching this ambition with value adding barrels requires hard work.

There are four pillars in Statoil’s strategy to maximise recovery from the offshore assets: 1. Safe and cost-efficient operations.

2. Reduce drilling and completion cost and time.

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3. Improved technologies for reservoir monitoring.

4. IOR techniques to produce trapped and bypassed oil.

“Many of our fields are approaching the tail end or are actually in the late part of the tail, so having an infrastructure and topside facilities which are efficiently run and cheap to maintain is a key issue in order to produce the last barrels,” Fevang says Reducing drilling and completion cost and time is vital in order to reach the company’s IOR goals. Time and cost spent on plugging wells is part of this picture. Over the next years, the well construction processes will be improved by implementation of automated systems. This is paramount for improving the company’s drilling and well construction process and a prerequisite for increased and accelerated production.

Improving the recovery will be achieved by locating undrained or partly drained areas and by mobilising trapped oil.

Geophysical reservoir monitoring plays an important role in locating areas with potential for additional recovery.

4-D seismic has assumed a significant

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EOR special supplement Core Samples from the Johan Sverdrup field Picture: Harald Pettersen, Statoil

role in finding new drilling targets for the last 20 years. On the Gullfaks field alone more than 20 wells have been drilled based on 4-D seismic and these wells have contributed to more than 64 million barrels of additional oil. Seismic cables for permanent reservoir monitoring have now been installed on two of Statoil’s fields (Snorre and Grane) to get a more detailed understanding of where the undrained oil is located.

Enhanced oil recovery As with almost every oil-producing region, water injection forms the backbone of Norway’s recovery technique. Years of refinement mean that water flooding is “very efficient” here, but gas injection has also played a significant role in the impressive oil recovery achieved on the NCS. In addition, chemical EOR is also an important focus of the R&D portfolio.

Fevang outlined recent work in polymer flooding, while other projects had used water diversion techniques to raise production from permeable reservoirs. One such recent example is the water diversion pilot with Silica gel on the Snorre field.

“We think it is the more conventional offshore, heavy oil reservoirs which present the largest target for chemical EOR methods when it comes to polymers,” he says. The company is now looking at implementing some of these techniques in early stage development of Norway’s newest giant field – Johan Sverdrup.

The giant Johan Sverdrup field – holding reserves of between 1.7 and 3 billion barrels of oil equivalent, and where these pilots are evaluated – presents challenges. “We need polymers to be very sustainable and not to break down over longer times at harsh conditions. Onshore, the main well spacing is far below 500 metres – and we’re talking about extending it up to 5 km for Johan Sverdrup,” Fevang noted.

Back to basics There is a tendency to consider EOR as a number of set techniques which can enable operators to produce more oil, but this is perhaps a narrow-minded view. Across its operations, Statoil considers the process of improving and enhancing recovery more holistically, from “new drilling techniques which enable us to create extended and far-reaching wells,” to standardised subsea NEWSBASE

infrastructure. The latter aims to create “plug and play” solutions, akin to the architecture of computer peripherals, with the intention of reducing costs and encouraging more co-operation.

In this sense, he adds: “Statoil is focused getting the cost down and on value barrels; because if we get the costs down we will get the barrels.”

So are there any technologies the industry is missing out on? “If only I knew which technology is overlooked!” he exclaims. “We are constantly looking for any potential game-changer within the entire IOR value chain. In 2014 we opened a new IOR laboratory focusing on fundamental understanding and developing new IOR technologies.”

IOR has a high focus in Statoil – even in a period of relatively low oil prices. The company’s R&D programme within IOR is strengthened and the co-operation with the world leading universities and research institutions re-enforced.

And as a final note, he says, “Technology is essential, but more than technology is required: i.e., a systematic and continuous effort to identify, evaluate and implement EOR measures.” n

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July 2015

EOR special supplement

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

F

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

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

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

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

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

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

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

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

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

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

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

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

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EOR special supplement Below: A Glori field technician collects quality control samples from an injection well under continuous AERO treatment

needed to encourage their growth.

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

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

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

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

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

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

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

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

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

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

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

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

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July 2015

EOR special supplement A finger of microbial biofilm growing on AERO nutrients and disrupting the oil-water interfacial tension

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

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

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

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

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

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

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

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

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

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

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

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

Chemistry in the Oil Industry XIV Chemistry: Challenges and Responsibili:es

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Registra:on now open! log onto www.rscspecialitychemicals.org.uk for further details

Special Events this year include: Keynote Lectures by Cuadrilla and the Environment Agency

Student Lectures, Posters and Exhibi:on

•

The focus will be on Unconven:onal Resources and New Chemistry to enhance the profitability of new fields or to extend the economic life of mature wells. The industry’s responsibility to do this safely whilst protec:ng the environment is paramount.

•

Geology and Geochemistry

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Hydraulic Fracturing (new fluid design • & remedia4on technologies)

New and Green Chemistry

•

Drilling

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Enhanced Oil Recovery (EOR/IOR)

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Scale & Corrosion Inhibi4on

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Regula4on and Economics

Chemistry applied to Unconven4onal Resources

This interna:onal symposium is organised by the Royal Society of Chemistry Speciality Chemicals Sector and the European Oilfield Speciality Chemicals Associa:on

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InnovOil

July 2015

EOR special supplement

Back CO2 for the future A new report by SCCS outlines the path to deploying CO2-EOR in the UK and Norwegian North Sea

T

he force behind carbon capture and storage (CCS) in the North Sea has picked up increasing momentum in recent years, not least as a result of the work being done

by Scottish Carbon Capture & Storage (SCCS). The issues of maturing oil reservoirs and the need to address carbon emissions have intensified pressure on policymakers and industry to push for novel, sometimes radical solutions.

Yet using CCS to the industry’s advantage could have the potential to transform both production and the supply chain – if such radical changes could be made. In its latest report “CO2 Storage and EOR in the North Sea,” SCCS argues, with good reason, that “CO2-EOR has the greatest potential for improving North Sea production … [unlocking] between 3,000 million and 6,000 million barrels across UK and Norway. That is equivalent to two or three super-giant oilfields.” But this result is only possible if government and stakeholders take bold action, involving power generators, users and the oil industry.

CO2-EOR follows similar principles

to the other EOR methods examined in this issue. CO2 is injected into a reservoir as liquid, quickly becoming a miscible solvent in the oil under high pressure and temperature. The oil, made more viscous by the CO2, can then be extracted more easily. Once topside, the CO2 is separated from the hydrocarbons and can be re-used or stored. In terms of added barrels, it has the potential to increase recovery from depleted reservoirs by around 10-15%.

Slow progress Thus far, as Professor Stuart Haszeldine comments in his introduction, “Critical factors slowing this development have been the large financial cost of investment, requiring subsidy for capital costs and price support for operational costs by national governments.” Other factors, including the lack of reliable feedstock – a 10- to 15-year project might require 2-5 million tonnes of CO2 per year – and the lack of conversion and recycling facilities, and their would-be investors, have also impeded a wider uptake.

At present “there currently appears little appetite among oil investors to develop NEWSBASE

CO2-EOR projects, partly as a result of multiple failed attempts to develop CCS and CO2-EOR projects in the North Sea.” SCCS’ report details costs and potential strategies to address this. Government leadership plays the most important role, owing to the number of ways in which production, supply and use could be encouraged. Analysis of possible fiscal incentives by Element Energy, Dundas Consultancy and Professor Alex Kemp of the University of Aberdeen suggests field allowances – tax breaks for pre-defined development conditions – would be one strong way to push operators towards CO2-EOR. “Several types of field allowances have been introduced in recent years, including ultra-heavy oil field, ultra-high pressure/ high temperature field, small oil or gas field, deepwater gas field [and] brownfield,” it suggests. “If structured efficiently, field allowances encourage new investments and maximise tax receipts without incurring substantial deadweight (incentive given – incentive required) losses.”

In this case, allowances based on “unit development cost with petroleum

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July 2015

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EOR special supplement

Predicted UKCS CO2-EOR oil production “Go-Slow” scenario l Cumulative oil production: 90 million barrels l Cumulative CO2 stored: 50 Mt

Additional oil potentially recoverable from the UK North Sea, using different EOR methods (McCormack PILOT 2014). These volumes are “unrisked”, so ultimate recovery may be less.

EOR Process Estimated EOR Potential (mmstb) Miscible Hydrocarbon flood 5,400 Miscible CO2 Injection 5,700 Surfactant/Polymer (Chemical EOR) 4,800 Polymer (on its own) 2,100 Low Salinity Waterflood 2,000

“Pragmatic” scenario l Cumulative oil production: 350 million barrels l Cumulative CO2 stored: 190 Mt

“Push” scenario l Cumulative oil production: 1 billion barrels l Cumulative CO2 stored: 550 Mt

Source: SCCS/Element Energy

revenue tax (PRT) removal” would be the most efficient way for the first beachhead projects to go ahead, likely in the early 2020s – if additional investment is forthcoming – the authors say.

In its “Push” scenario, a deployment scenario with strong CO2 EOR policies and uptake, 550 million tonnes of CO2 could be sequestered, and “incremental UK oil production could be as high as 1 billion barrels.” The UK’s tax take on this could then be as high as GBP4.3 billion, based on oil at US$90 per barrel – quite a prize for a basin currently in decline.

Performance and technology Yet in the “EOR Performance” section, Dr Peter Olden, Professor Eric MacKay and Dr Gillian Pickup of Heriot-Watt University note that this is not without its challenges. The authors report that “maintaining the reservoir pressure high enough to ensure CO2 miscibility is key.”

Because CO2 is more easily compressed than water, this may involve injection at higher rates than would be required for equivalent water flooding.

Ultimately, the modelling suggests

that the more CO2 can be injected, the more oil can be extracted, within certain parameters. From a storage perspective, this also means that more CO2 is able to be stored in the reservoir. The challenge in this respect then becomes sourcing enough feedstock to guarantee production.

Dr Peter Brownsort of SCCS tackles this in the report’s supply chapter. From a technological perspective, shipping would be the optimal method at first, offering the flexibility of supply necessary for early operations.

While small CO2 transport vessels are already in commercial operation for the European industrial gas, food and drink industries, “The interface between shipping and well injection is not widely covered for CO2-EOR,” Brownsort notes.

The technology is broadly the same as that used to transport other cryogenic liquids, e.g. LPG or LNG, but, as with LNG, liquefaction and the energy needed to perform it is the most expensive part of the process. In terms of expenditure, Brownsort estimates that “costs for distances relevant to the North Sea range between 10 and 30 euros/tonne of CO2.

NEWSBASE

The greatest costs are associated with liquefaction and the shipping operation.”

Over short distances, pipelines are more cost-effective, but shipping offers a more flexible and cost-effective option for longer distances.

In addition, while loading and offloading cargoes from ship to onshore is well established, Brownsort notes that “offshore offloading at a storage/EOR site requires novel techniques and is a main area of technological uncertainty in the transport system.” In this case, there are still some innovations to be made.

What is clear from the report, and to potential detractors of CO2-EOR, is that how effective its deployment could be, and the ways in which it could address a number of issues facing the energy sector.

But that potential will only be realised if policymakers and the oil and gas industry take action at national and international levels. In the meantime, as ever, SCCS will continue to encourage the collaborations needed to deliver the infrastructure needed to drive North Sea CCS forward. n

SCCS’ report “CO2 Storage and EOR in the North Sea” is available here.

InnovOil

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July 2015

EOR special supplement

Attracting Attension with EOR

The Attension High Pressure Chamber from Biolin Scientific allows operators to simulate the high-pressure, high-temperature environments of oil reservoirs when studying wettability – ideal to aid any EOR project

U

sing carbon dioxide (CO2) in enhanced oil recovery (EOR) is not simply a matter of pumping the gas in and getting oil out.

The interfacial tension – the adhesive force between a liquid and another solid, liquid or gaseous substance – between hydrocarbons, water and CO2 play an important role in determining the effectiveness of the CO2-EOR. The wettability – how a liquid spreads across another liquid or solid substrate – of oil reservoirs can be characterised by the Amott test, the US Bureau of Mines tests (USBM), and through contact angle measurements. In the Amott test, an oil-saturated core sample is placed on a measuring cell filled with brine solution and the amount of oil extracted is measured. The USBM test relies on capillary pressure curves obtained by the centrifuge method.

Both of these methods are limited in that they provide a quantitative value of the wettability of a core only at atmospheric conditions. Contact angle measurements, on the other hand, enable the determination of the wettability of surfaces at high pressures and elevated temperatures more akin to reservoir conditions.

Wettability has a significant effect on the efficiency of EOR techniques owing to its effect on fluid saturation and flow behaviour in porous media.

There are three possible states of wettability: water-wet, with an oil contact angle of 105°-180°; intermediate-wet, with a contact angle of 75°-105°, and oil-wet at contact angles from 0°-75°. It is therefore vital that operators have a clear understanding of how EOR techniques are affecting these metrics.

Under pressure Adding to its Attension range of contact angle meters and precision tensiometers, Nordic instrumentation firm Biolin

Scientific has launched the Attension High Pressure Chamber for advanced wettability research in EOR. The chamber is an addon module for the Attension Theta unit, allowing users to perform interfacial tension and contact angle measurements in high pressures and temperatures.

The chamber enables the Attension Theta to make measurements at pressures up to 400 bar and temperatures of up to 200°C. This is ideal for operators evaluating wettability conditions within oil reservoirs and the performance and placement of supercritical fluids (SCF), supercritical CO2 or CO2 storage and polymer injection.

The chamber uses a unique piston design which is especially useful in any studies including surfactants.

Traditionally, the pressure is increased within a chamber by pumping more fluid into it, but when surfactants are used in the measurement, this leads to a rise in surfactant concentration, and results can be skewed.

In order to eliminate the issue,

SOLID

the Attension High Pressure Chamber enables pressure to be raised by using a movable piston inside the chamber. The unique piston will compress the fluid in the chamber without the need to pump in more fluid. Therefore, both surfactant concentration and measurement pressure can be controlled independently – vital for EOR research.

In addition, the Attension Theta itself can be fully automated, meaning measurements can be performed easily with a single click. For droplet formation, both manual and automated pumps are also available and the compact size of the unit means it could also be used in more spacesensitive labs offshore.

The Attension High Pressure Chamber is operated with OneAttension software, including features such as Automatic baseline detection and drop shape fitting, live analysis of results, ready-made experiment recipes for quick and repeatable operations and flexible and programmable frame per second rate for the camera. n Contact: Maiju Pöysti, Biolin Scientific

Tel: +35 8 (4) 09 022010 Email: maiju.poysti@biolinscientific.com Website: www.biolinscientific.com/product/ theta-high-pressure-chamber/

SOLID

SOLID

θ

θ

θ

OIL

OIL

OIL

WATER

WATER

WATER

105 < θ < 180˚ WATER-WET NEWSBASE

75 < θ < 105˚ INTERMEDIATE-WET

0 < θ < 75˚ OIL-WET

July 2015

InnovOil

page 21

EOR special supplement The maindeck of Captain’s bridge-link platform.

Picture: Chevron

New orders from Captain Progress on the North Sea’s Captain EOR project continues, with Jee this month awarded a FEED contract

G

iven the doom and gloom forecasts surrounding North Sea production, it is refreshing to see ground-breaking and major projects go ahead, especially those dealing with enhanced oil recovery (EOR).

One such project is Captain EOR, a major undertaking at the Chevronoperated Captain field, 68 miles (109 km) offshore Aberdeen. The field is a joint venture between Chevron (85%) and Dana Petroleum (15%).

EOR is needed to stem the field’s declining output, with Chevron taking the route of polymerised water injection. In 2013 net daily production averaged 25,000 barrels of liquids and 3 million cubic feet (85,000 cubic metres) of natural gas.

By its 2014 annual report, the company had posted a fall in oil production to net average daily results of 18,000 barrels of liquids, while gas remained steady at 3 mmcf.

Major investments will see the polymer injection capabilities added to existing Captain facilities via a new bridge-linked platform (BLP). The new platform will be tied into existing facilities and will be used to store, mix and pump polymers for

injection into the reservoir. The project entered front-end engineering design (FEED) in in December 2014, with Amec Foster Wheeler being awarded the facilities engineering contract for the BLP, as well as responsibility for the platform’s brownfield tie-ins to the existing facilities.

The development includes 4-D seismic imaging, horizontal drilling and pump technology, while development drilling is expected to take place from 2015 until 2020.

“This is a prestigious and challenging project that encompasses both greenfield and brownfield engineering, procurement and project management services, so is an excellent fit for our capabilities,” said Nick Shorten, managing director of Amec Foster Wheeler’s Greenfield business in Europe, at the time.

Wood Group Kenny Caledonia, meanwhile, will undertake the subsea engineering of the trees, wellheads, controls and the polymer injection flowlines to the subsea injection wells.

A final investment decision (FID) is scheduled for 2016, but proven reserves for the project have not yet been recognised.

NEWSBASE

JEE-OR Most recently, subsea engineering firm Jee has been awarded a contract by Amec Foster Wheeler for the FEED of a jacket rigid polymer injection riser package, including J-tubes.

In a statement, Jee head of engineering Jonathan McGregor said: “The everchanging downhole environment represents a challenge when injecting chemical agents into existing reservoir fluids. The work carried out

by Jee’s highly experienced engineers on this innovative project will allow for informed decisions to be made, with the aim of successful long-term oil recovery.”

The lack of many major EOR developments in the North Sea to date also presents a challenge. In terms of Jee’s approach to risers, “the main issue is material selection, since there is no experience with polymer lines in the North Sea,” a Jee representative told InnovOil. The firm remains pleased to be a part of a unique development. “It is a first in the North Sea and it is a project which the Department of Energy and Climate Change [DECC] has strongly encouraged since the initial development of the Captain field,” it added. n

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InnovOil

July 2015

EOR special supplement

SWIT ™ and wisdom on subsea water injection

Technology from NOV/Seabox is a new component in the subsea factory, offering enhanced water treatment and placement for injection wells

W

ater injection – as has already been mentioned in this issue – is common to every oil-producing region as a method for enhancing or maintaining production. Where the process becomes more complicated is in deciding injection well placement, processing and/or cleaning the water, accurately injecting it into the reservoir and potentially combining it with other IOR and EOR techniques.

At present, much of this processing is done on topside structures. Initial reservoir information gained from field appraisal wells alone means that many of the reservoir characteristics and fluid behaviours are not well understood until the project is far into field production. Because of this, decisions on how and where best to use the topside injection capacity are usually made too far in advance.

Many operators are working towards full subsea field development, pushing technology providers to adapt many of these processes into smaller, automated forms. Subsea water intake and treatment SWIT™ technology aims to do just that for injected water.

Developed by Norwegian firm Seabox – now a subsidiary of NOV – the SWIT™ technology combines all the necessary processes for subsea water processing, providing clean water directly from surrounding seawater and preparing it for use in well injection and other applications.

What’s in the box?

Placement of the unit on the seabed removes many of the limitations of topside water processing. Conventional topside equipment will require multiple types of pumps, filters and chemical treatment packages. Given the freedom of space and weight constraints, a SEABOX™ unit is made up of far fewer components and offers more extensive capabilities from a single package.

The primary SWIT™ unit – the SEABOX™ – has no moving parts and generates its own chemicals on the seabed

via electrolysis. It is comprised of electro chlorination (EC) cells, a large still room and hydroxyl radical generation (HRG) cells prior to being delivered to an injection pump. Raw seawater enters through the EC cells in advance of 1-2 hours of residence time allowing a “chlorine soak.” A complete reaction of the oxidant and organics takes place and solids sedimentation removes inorganic solids to ca. 20-µm levels.

The water held in the 8m x 8m x 7m unit provides injection capacity of 40,000 barrels per day, typically enough to supply at least two injection wells. Inside, the slow movement of water means that sediment particles are separated without the need for a filter. At regular intervals, this fallen sediment is jetted out of the unit.

Hydroxyl radicals are then introduced via electrolysis in the HRG cells, further decomposing dead organics and killing any residual bacteria resistant to the chlorine soak. The resulting water quality is superior to that achieved via other topside systems, with very good levels of disinfection and 99% of particles greater than 24 µm removed. This is also far greater than the coarse filtration used in conventional water injection, which usually removes solids to level of around 80 µm.

In most cases, a SEABOX™ unit will be connected to an injection pump downstream, which draws the water through the unit and delivers pressure at the wellhead. The resulting pressure loss NEWSBASE

across the SEABOX™ unit is only “a few centimetres water gauge.”

Currently rated to work in depths of up to 3,000 metres, the system’s reliability and integrity is helped by the fact that there are no rotating or moving parts. The SEABOX™ unit itself has a typical power requirement of less than 10 kW, easily interfaced to subsea infrastructure.

Replace or re-deploy The still room – a non-corrosive glass-fibre reinforced epoxy (GRE) tank – contains a detachable treatment unit (TU), where all critical components are held. These 7-tonne TUs will run for between 4 and 5 years before replacement, a process which can be undertaken by a light intervention vessel.

The TU fits into standard containers and can then be transported back onshore or the whole unit can be redeployed in a new location.

Replacement is one of the rare moments of direct interaction the operator should have with SEABOX™ unit. Built to conform to global standard protocols, it is designed to be integrated straight into existing systems. Control is available via a topside host or an onshore/global operation centre as required; pilot projects run between 2009 and 2013 allowed operators at the Seabox office to monitor and control the SEABOX™ unit in the Oslo fjord from over 500 km away.

Likewise, the SWIT™ technology is designed to be incorporated into standard

July 2015

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EOR special supplement Fully integrated SWITTM facility

Xxxxx

subsea infrastructure. The 40,000 bpd unit will fit into one section of a 4-slot frame, with a water injection pump in another and two slots left available for injection wells.

Seabox has worked with AkerSolutions to ensure that the subsea water treatment unit, SEABOX™, can be integrated seamlessly throughout the treatment and pumping phases.

AkerSolutions has also studied alternative configurations for use in various environments, from suction pipes to steel frames, where the seabed permits. This even includes modular applications, meaning most subsea sites are suitable for SWIT™ deployment.

Working in tandem The other great advantage of the SEABOX™ unit lies in its ability to integrate with more complex processes usually reserved for topsides. In 2013, Seabox conducted a two-year joint industry project (JIP) funded by a number of E&P companies and NRC Demo 2000. The 9-month seabed trials within this JIP assessed the SEABOX™ unit performance in conjunction with several water treatment methods such as microfiltration and spiralwound membranes to address the chemical

problems of souring, scale and water wettability – the bonding or adherence of water to solids.

In some reservoirs, injected water must have sulphate ions (SO42-) removed to avoid scale build-up in the well and reduce souring potential within the reservoir. In more recent trials, low-salinity water – water which has been treated to reduce salt content – has shown promise in EOR applications. Both treatments require membranes to remove the respective ions, but if poor feed quality water is used the membranes can quickly become fouled, meaning the process is halted while the equipment is cleaned – both timeconsuming and expensive to operators.

By combining SWIT™-purified water with these treatments, membrane fouling is substantially reduced and more reliable, meaning operators can spend more time producing and less time maintaining. The above-mentioned JIP project allowed 6-month periods of operation with no required maintenance or downtime, and no loss of performance.

The company’s most recent JIP, begun in 2014 and again backed by several E&P firms and NRC Demo 2000, is to ensure that all aspects of a subsea membrane NEWSBASE

treatment plant are qualified for a field application. In areas where “gaps” in technology qualification exist, further work is ongoing and Seabox expects the technology to be qualified for use this year.

The SWIT™ technology’s value creation is in its flexibility and versatility. The movement of water treatment to subsea not only saves space on topsides, but allows operators more scope to change the flow and placement of water injection according to the needs of the reservoir.

Sweep efficiency is improved, reliability is greatly improved and overall CAPEX is reduced through the use of modular subsea components the decoupling of water injection wells and production wells.

A variety of field applications is already progressing through oil company design / decision gate processes. These applications range from enhanced gas recovery to connecting SWIT™ technology back to topside structures to supply them with cleaner water. The only question now is: what isn’t in the box? n Contact: Torbjørn Hegdal, Business Development Manager Email: Torbjorn.Hegdal@nov.com Web: www.nov.com/seabox

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InnovOil

July 2015

EOR special supplement

Looking into the IRIS

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

E

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

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

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

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

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

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

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

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

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

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

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

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

Next, work is carried out at core scale.

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

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

July 2015

InnovOil

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EOR special supplement

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

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

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

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

NEWSBASE

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

With the long-term financial

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July 2015

EOR special supplement IRIS’ full-scale rig mock-up, ULLRIG

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

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

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

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

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

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

There are, Roman and Ying note, “lots

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

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

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

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page 28

The Spirit of the age

InnovOil

July 2015

COMMENTARY The MEGI engine of the Teekay Corporation’s LNG Creole Spirit

Tim Skelton investigates the Creole Spirit, DSME’s latest state-ofthe-art and superefficient LNG carrier

T

he first of a new generation of fuel-efficient LNG carriers was recently launched in South Korea, promising cost savings and environmental benefits for the fleets of the future.

Built by the Daewoo Shipbuilding & Marine Engineering (DSME) at its shipyard near the town of Okpo, at the southern tip of the Koran peninsula, the Creole Spirit is one of a fleet of nine twin-engine M-type, electronically controlled, gas-injection (MEGI) LNG vessels ordered by marine energy transportation, storage and production specialists Teekay Corporation.

With a cargo capacity of 174,000 cubic metres of LNG, the new carriers are no larger than existing vessels. Instead, what sets them apart is their state-of-the-art propulsion systems, which are designed to save around 30% of the fuel used.

The most fuel-efficient carriers currently in service, which operate using dual-fuel diesel-electric (DFDE) propulsion systems, consume around 125 to 130 tonnes of fuel oil equivalent per day. The new vessels are expected to reduce this to around 100 tonnes per day, including sea margin (an adjustment factor to allow for rough weather, fouling of the hull, etc.). The lower fuel use will also result in a correspondingly large drop in CO2 emission levels.

MAN-power The new two-stroke engines are built by MAN Diesel, and are a development on the German company’s previous generation of engines. The ME-GI is based on the ME (Electronic) engine design, which has already been in production for more than a decade.

Thousands of these models are currently in service, between them clocking up millions of hours of operating experience.

The ME in turn is a variant on the MC engine, which has been in production for over 20 years, with a proven track record for reliability and maintainability. The GI version is a longer stroke version of its predecessors. This, combined with the use of a larger propeller, results in higher propulsion efficiency.

Two key elements central to the new design are a Burckhardt compressor, and a partial reliquefaction system. The compressor is able to take any boil-off gas from the LNG cargo tanks, and pressurise this up to 300 bar, whereupon it can be injected directly into the engine cylinders.

Pilot oil is used to begin the combustion process. This is already burning when the gas is injected, causing it to ignite instantaneously.

As a result there is no reduction in power rating, knocking or methane slip, NEWSBASE

as is often the case with Otto Cycle (lowpressure injection) engine types.

At the end of the cycle, the partial reliquefaction process then takes any excess unused gas away from the engine, and returns it to a liquid state. This can then be pumped back into the cargo tanks, by reducing the excess gas pressure, via two Joule Thomson valves, from 300 down to 3 bar.

Efficiency evolution The gas injection system is not the only advantage offered by the new engines.

Their two-stroke format reduces the number of cylinders that will require overhaul, thus cutting maintenance costs.

A reduction in the size of the engine’s electrical systems, and the use of a passive partial reliquefaction system, also improves efficiency and further reduces unit freight costs, Teekay claims.

“MAN’s ME-GI engine is highly suited to the LNG carrier market and is recognised as the most fuel-efficient gas-burning engine on the market. We are confident that the quality and fuelefficiency of these engines will be very attractive to our customers,” Teekay CEO Peter Eversen said.

Moreover, the ME-GI system is a design “evolution” rather than a

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COMMENTARY Teekay’s first M-type, Electronically Controlled, Gas Injection (MEGI)-powered LNG vessel, Creole Spirit, was floated out at the Daewoo Shipbuilding & Marine Engineering (DSME) shipyard in South Korea

“revolution.” Basing it on an established diesel platform means that most of its core features are already tried-and-tested technology.

Further risks are mitigated by using an established manufacturer for the compressor. “Burckhardt is the world’s leading manufacturer of high-end, highcapacity, high-pressure compressors” say MAN Diesel. “They have a long and very well established track record of manufacturing very robust and reliable compressors for the marine industry.”

Furthermore, a holistic approach was applied to the design of the entire propulsion unit, from the compressor to the engine components, including the control and instrumentation systems.

The ship’s owner, engine manufacturer, compressor manufacturer, control system supplier, and the DSME shipyard all

worked together to create a collaborative system.

Safety at sea One critical element of safety concern was always going to be the gas injection system. To keep risks to a minimum, gas is led from the LNG storage tanks to the engine via a dual-walled pipe. The inner pipes are tested up to a pressure 1.5 times greater than the intended operational pressure of 300 bar.

The thickness of the outer pipes has also been specifically sized to withstand the maximum rupture pressure that might come from the inner pipe.

“The pipes are further located so that heavy objects such as cylinder covers and liners not can be dropped on the piping,” MAN say. “Investigations have also shown that a rupture of the inner NEWSBASE

fuel pipe is not able to damage the double wall gas pipes from the outside.” In the unlikely event that a leak does occur in the inner pipe, on-line hydrocarbon detectors will cause the system to immediately revert to fuel oil operating mode. The system will also automatically purge the lines of any dangerous gases, using nitrogen.

Now that the hull of the Creole Spirit has been floated – and less than three months after its keel laying ceremony – DSME says it expects to spend around eight months installing the LNG cargo containment system. Once this step is completed, the vessel and its equipment will be put through the required tests and undergo sea trials.

The Creole Spirit is expected to enter service under a charter contract with Cheniere Energy early in 2016. n

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Innovators chip away at decommissioning costs As decommissioning begins to rise on the list of operator priorities, Jeremy Bowden reports on the firms stepping up to the challenge, offering new, innovative and low-cost services

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s a growing number of North Sea oil and gas fields head towards the end of their productive lives, and their date of decommissioning approaches, more companies are devoting time and money to developing new techniques and products to address problems and cut costs.

These companies range from services specialists such as Baker Hughes, to operators such as Marathon, and well project managers Acona UK and Jee, all of which have announced advances over recent weeks. Their claims include savings of up to 40% on rig-based abandonments, which could shave billions of pounds from the decommissioning costs of the 5,000 wells and 600 platforms in the North Sea alone.

Innovation in contract behaviour can also cut costs by taking a fully collaborative approach with rival producers, which alone could save between 30% and 40% of plugging and abandonment (P&A) costs, according to Marathon Oil’s global decommissioning manager, Jim Christie.

A group of leading operators at the start of what will become a conveyer belt of big decommissioning projects – including Marathon – are now co-operating by offering suppliers a guaranteed pipeline of work.

This can help reduce the risk of equipment downtime, which minimises the average contract rate required, encourages suppliers to invest in new technology, and in equipment that has a limited market, such as light well intervention vessels.

Low-cost, high-quality While oilfield operators tend to avoid collaborating in upstream exploration

and development in order to have as much control over their schedules as possible, with decommissioning the focus is more on quality and cost, rather than deadlines. The advantages of sharing a decommissioning campaign include economies of scale, knowledge-sharing and an increase in available expertise. Contractors such as Helix Well Operations have already brought together operators in joint subsea P&A campaigns.

Reducing technical costs in the process remains the focus of innovation for most.

Acona UK’s business development manager Nick Ford said recently that the company’s key offering to operators was its ability to drive down decommissioning costs: “With evidence from the rig-based abandonments performed to date, we estimate that, through the utilisation of our contracting strategies and operational performance, we have realised savings of between 30-40% ...

Decommissioning is a big focus for us and we are working on several different angles for our offering to operators.”

Baker Hughes said it had been focusing its efforts on improving technology and reducing the costs of cutting and pulling well casing, used in decommissioning if well integrity is an issue. Its new techniques are designed to minimise the time spent over a well with a drilling rig or vessel, boasting saving of up to US$300,000 a day. The Harpoon technology it uses applies familiar hydraulic cutting techniques alongside a large number of high-tech improvements. It also means the spear can be re-set, allowing multiple attempts with a single trip.

The services giant has also introduced more wear-resistant cutters to improve the mechanical milling process and has been NEWSBASE

Left: A North Sea rig anchored in the Cromarty Firth

working on improving cement evaluations.

The main innovation force behind this is to create an acoustic wave directly on the casing rather than inside the logging tool, making it easier to evaluate wells containing contaminated, lightweight or foam cement.

Waste not …

Elsewhere, groups are looking at other specifics of decommissioning. A group including Decom World, DNS, Zero Waste Scotland and Jee is looking at a variety of areas, including pioneering re-use and salvage options for concrete subsea mattresses. This involves innovative new solutions for subsea mattress removal, which would work without diver interventions during the lift procedure.

The result, it is hoped, will be both improvements in safety and a reduction in costs.

Jee subsea engineer Adam Smith said: “[The project] will form a basis for economic and environmental assessment of mattress conditions and the options for removal and re-use going forward. We also helped to identify the criteria required to determine whether subsea mattresses should be removed or left in situ, the main considerations being the safety of the subsea divers and the environmental impact.”

Jee has developed a number of

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COMMENTARY

Above: The Baker Hughes Harpoon™ cut and pull spear is a robust tool designed for cutting and pulling casing in operations associated with plug and abandonment, slot recoveries, and where cement bond and scale build-up are unknown.

NorSea Group (UK)

innovative suggestions for the re-use of mattress concrete, including tidal lagoon structures, the construction of artificial reefs to encourage new sea life and in road-laying foundations. The latter would mean less new concrete needed to be produced and a corresponding reduction in carbon dioxide emissions.

Zero Waste Scotland CEO Iain Gulland added: “[Initial] findings point to some exciting cross-over potential with other sectors, such as offshore renewables.

Circular economy practices present a terrific economic opportunity … and we can best realise this by collaborating across sectors and industries.”

Part of the service Problems often arise when dealing with older technology – most wells that are being decommissioned were drilled several decades ago, using different generation technology, working to different regulatory requirements. If there are insufficient well data this can lead to considerable challenges.

As the decommissioning ball gets rolling, more companies are devoting time and effort to developing their capabilities in the area. For example, NorSea – which has recently begun decommissioning the Renee and Rubie fields – is switching focus: “We are primarily known as a logistics

and base services company servicing the offshore industry; but as part of our future growth strategy, we are developing our decommissioning capability,” said Walter Robertson, managing director of NorSea Group. The contract requires reuse of material, including 1,000 tonnes of concrete mattresses, 200 tonnes of pipework and skid units, manifold valves and a 17 tonne crossover manifold.

As more wells and platforms are completed, lessons are learned and more efficient techniques are introduced, many of those involved expect to see a steady decline in costs and in hours of input. In the case of the Brent platform decommissioning programmes, for example, stakeholders NEWSBASE

from over 180 organisations, including the University of Aberdeen and independent scientific experts, have been involved for almost nine years already.

Once such high-profile operations are complete, the combined input will undoubtedly translate into something more routine, driving down costs – and especially if future development activity remains weak and service companies find themselves looking for new markets. We may even see the oilfield services stalwarts launching new, decommissioning-only ventures, each bringing new innovations and increased competition – all of which is good news for operators anxiously looking at the impending cost of ceasing production. n

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Speeding up inspections with Magna Scan Riding high on its success and acclaim at last month’s Offshore Technology Conference, InnovOil profiles the award-winning Magna Subsea Inspection System™

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ipe inspection remains one of the top priorities in terms of operators looking at asset integrity management. In a recent survey by the Pipe Tech Global Summit – and featured in the April edition of InnovOil – 25% of respondents identified corrosion as the primary cause of pipeline failure. Others drew attention to the importance of new innovations for the inspection of un-piggable pipelines.

As a result, inspection tools are rising to the challenge, and with more flexibility and capability than ever before. Oceaneering’s Magna Subsea Inspection System is one such innovation, recently recognised by the 2015 Offshore Technology Conference (OTC), at which the system won a Spotlight on New Technology Award.

Oceaneering cites the “innovative technology, broad appeal to the industry, proven capabilities through full-scale application, and significant impact with benefits beyond existing technologies,” as the driving reasons behind the OTC committee’s decision.

Rapid scanning The Magna Scan is an ROV-deployable pipeline scanner, combining Oceaneering’s automated Sea Turtle™ scanner with other proprietary ultrasonic scanning technology.

It can be deployed from any ROV capable of providing the power and communication link required.

It allows operators to inspect and monitor assets – even un-piggable lines – at rapid speed, without halting or disrupting production – all in a single trip.

“The entire system is usually deployed from topside, either held in the ROV

manipulator or in a basket attached to the ROV. When the inspection site is reached, the ROV places the Sea Turtle on top of the pipe to be inspected, and the scanner is retained by its magnetic wheels,” Oceaneering senior inspection engineer, Donald McNicol explained to InnovOil. The ROV then pulls back, and observation of the inspection progress is carried out using the ROV’s camera systems. As the Sea Turtle is tethered to the host ROV, the vehicle maintains position as the Sea Turtle is driven along the top of the pipe, under the control of an operator in the ROV control room.

The system inspects 360° around the pipe, providing real-time data on the wall condition of ferrous and non-ferrous structures. Magna Scan works on pipelines of up to 4-inch (101.6-mm) diameter, on thicknesses of 0.062-1.125 inches (1.5-28.57 mm), and through coatings of up to 0.070 inch (1.77 mm).

Ultrasonic scanning – including lamb NEWSBASE

and shear horizontal guided waves – detects wall loss and defects in the pipe, including corrosion, isolated pitting, cracking and other potential anomalies.

The use of the Sea Turtle scanning unit, in combination with a larger ROV, means the speed of data gathering is a major differentiator. The system scans at around 6 inches per second (just under 10 metres per minute), based on operations of around 1,000 feet (300 metres) per day.

“The data set is presented in a number of ways, with the most basic of which include the amplitude and time of flight of the signal. This basic data is also integrated to show change in amplitude and time of flight, so that variations caused by anomalies can be quickly and simply identified, along with the location,” McNicol says. There are additional data display modes, the selection of which is dictated by the particular application, geometry and material being inspected. n

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News in brief

OPEC and IEA paint bullish picture Both OPEC and the International Energy Agency (IEA) published bullish monthly oil market reports this month, the latter revising upwards global demand growth forecasts for the year to exceed even the former’s strong projection, itself raised a month earlier.

The sentiment was reflected in a spike of almost US$5 per barrel for the second month running in the average price for OPEC’s basket of crudes – which the group’s report claimed justified members’ decision during their biannual meeting on June 5 to leave the collective production ceiling unchanged, despite oversupply fears.

However, record OPEC output during the month and the two surveys’ agreement on the fact though not the degree of continued non-OPEC supply growth for the year injected a more bearish note, as did a World Bank forecast lowering projected 2015 global economic expansion to 2.8% from 3%.

OPEC production reached its highest level since August 2012 in May, up by a marginal 50,000 barrels per day on the April figure to hit 31 million bpd. Saudi Arabia’s production continued at near-record levels of 10.3 million bpd – providing the kingdom with some consolation for being displaced by the US as the world’s biggest oil producer in BP’s authoritative Annual Statistical Review, released on the same day.

Kuwait recorded the sharpest monthon-month fall, assumed to reflect the loss of suspended production at the Partitioned Neutral Zone (PNZ) – shared with Riyadh – as a result of an acrimonious dispute with operator Chevron of the US. The main production increases were registered by Angola, which bounced back from a one-off outage at a major project during April, and by Iraq, which recorded a new monthly high of around 3.3 million bpd – according to direct communication from the authorities there. The latter factor is becoming a regular feature of monthly reports and an issue side-stepped by OPEC in its official communiqué at the end of the Vienna meeting, which focussed on the healthy demand outlook and improved price levels.

With the ceiling of 30 million bpd already being breached and OPEC’s own forecast 2015 average demand for its crude remaining at only 29.3 million bpd, much is resting on

the success – limited thus far – of driving higher-cost producers out of the market by maintaining high output in a lower price environment.

Despite repeated references in OPEC’s monthly reports to the declining US rig count as evidence of the policy’s efficacy, North American supply appears by the group’s own admission to be bearing up.

Average first-quarter US output of 13.56 million bpd was up by 68,000 bpd on the 2014 figure and is expected to remain at similar levels throughout the full year, with the latest report acknowledging that the bald rig count data could be masking the greater efficiency of those still in use.

The US Energy Information Administration (EIA) provided a more technical explanation in its own monthly report published a day earlier, saying that US output had continued to increase as “producers work through the backlog of uncompleted wells and achieve potentially better completions with higher initial production rates.” Decline was expected to set in from June, however.

The IEA raised its forecast for 2015 non-OPEC supply growth by a hefty 195,000 bpd from its last report to 1 million bpd – describing production growth as “exceptionally high” while accepting that lower prices would eventually curb the trend.

“Lower oil prices and a drop in capital spending are taking time to curb non-OPEC supply,” it said.

NEWSBASE

Fortunately for all suppliers, the various reports found more consensus on the consumption side – uniformly anticipating high demand throughout the remainder of the year. The IEA’s figure was particularly notable for being revised upwards by 300,000 bpd to 1.4 million bpd – leapfrogging the 1.2 million bpd now being projected by OPEC. The former body attributed the market strength to healthy global economic growth, a cold northern hemisphere winter and the effect of lower oil prices themselves stimulating higher consumption. The reversal of the last factor could weaken demand again during the remainder of the year. The average price of the OPEC basket of crudes rose by US$4.86 to US$62.16 during May alone, building on a US$4.84 increase in April.

Edited by Ian Simm ians@newsbase.com

Painful year continues for services companies The scale of the problems facing the UK well services contracting industry has been laid bare in a new report from Oil & Gas UK. The sector has seen a sizeable fall in

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News in brief

employment and a slowdown in demand that looks set to turn into an outright decline this year.

The negative trends come despite the fact that companies operating in the sector saw their revenue nudge up around 1% last year to US$3.24 billion, according to the report.

Earnings before interest and other costs also surged nearly 23% to US$591 million in 2014, ahead of forecast on the back of a strong performance in the first three quarters of the year.

But many have witnessed slower demand for their services in the second half of the year and are predicting worse to come. They expect revenues to fall nearly 23% this year to US$2.5 billion and possibly “even lower” as weak oil prices translate into a drilling activity downturn. Earnings are seen sliding by a similar percentage to US$456 million.

Investment and employment are also on the way down. The sector provided incomes for 16% fewer people in 2015 than the 15,339 it employed in 2013. Apprentices were the worst affected, with like-for-like job figures down 47% between 2013 and 2014, followed by graduate engineers with a 44% fall.

Technicians were in stronger demand, with a like-for-like job shrinkage of 3%.

Capital investment by well services contractors declined 30% last year to US$148.7 million – the lowest figure since 2010. Although a further fall is predicted for this year, this will be a slightly smaller 25%, companies predict.

The industry is taking remedial steps to address the problems. The report highlighted an intention by firms to develop shared industry tools such as standard contracts

that would help improve cost efficiency in the oil and gas industry.

“Well service contractors recognise the importance of talking cost and improving efficiency and they continue to invest in technology and processes to support these goals,” the report read.

“The companies suggest that standardising technologies across operators would greatly reduce manufacturing costs.

They also recommend that technology aimed at increasing the lifespan of wells and improving the effectiveness of maintenance programmes should be an area of focus.”

The 2015 report is collated from the responses of seven companies – Altus International, Archer (UK), Baker Hughes, Frank’s International, Halliburton, Read Cased Hole and Schlumberger Oilfield Services – which Oil & Gas UK says represents 85% of the sector.

Edited by Ryan Stevenson ryans@newsbase.com

ConocoPhillips exits Polish shale exploration ConocoPhillips is withdrawing from shale exploration in Poland because it has failed to find commercial volumes of gas, the company said on June 5. ConocoPhillips said its subsidiary, Lane Energy Poland, had invested around US$220 million in the country since 2009. Having drilled seven wells over its three Western Baltic

Shale exploration, Poland

concessions, the company reported that results had not been satisfactory.

“Unfortunately, commercial volumes of natural gas were not encountered,” said ConocoPhillips’ country manager for Poland, Tim Wallace. “We understand the disappointment surrounding this difficult decision,” he added in a statement.

ConocoPhillips also said it anticipated a charge related to the Poland withdrawal of around US$90 million pre-tax, and roughly US$30 million after tax.

ConocoPhillips was the last major foreign oil company left exploring for shale gas in Poland, after Chevron withdrew at the start of 2015. The move – which follows the exits of ExxonMobil, Total, Marathon Oil and Talisman Energy over the past three years – leaves Polish shale exploration largely in the hands of the country’s state-run firms.

A few smaller foreign independents, including San Leon Energy, also remain in the country.

While exploratory drilling has been carried out over the past few years, Poland has not seen a single commercial well start up, although San Leon has made a conventional gas discovery.

Global drillers were attracted to Poland in the belief that the Eastern European country would be able to replicate the shale gas boom seen in the US. In 2011, Poland’s former Prime Minister Donald Tusk said that he expected the first commercial shale gas to be produced in 2014, expressing hopes that it would help the country to significantly reduce its reliance on gas imports from Russia.

An initial blow to these hopes came in 2012, when Poland’s estimated shale gas reserves were revised down to 346-768 billion cubic metres by the Polish Geological Institute, from an earlier US Energy Information Administration (EIA) figure of up to 5.3 trillion cubic metres. Since then, a slump in oil prices over the past year has added to obstacles facing drillers. The reasons given by foreign firms for quitting Poland have also included geological challenges and unfavourable regulations.

Poland is one of the few European countries that allow hydraulic fracturing.

Other countries, including the UK, that technically allow fracking have seen other obstacles such as regulatory hurdles and local opposition hold up shale exploration efforts. In April, the German government approved new rules to restrict fracking, citing environmental and public health concerns.

Edited by Ryan Stevenson ryans@newsbase.com

NEWSBASE

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News in brief

EMAS AMC makes headway at Aasta Hansteen

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MAS AMC, the deepwater subsea division of offshore services provider EZRA, has completed the installation of 3 subsea structures at Statoil’s Aasta Hansteen field, the deepest such operation in Norwegian waters.

EMAS was awarded a contracted in March 2013 to deliver and install two 4-slot templates and one singleslot template to the field, at a depth of around 1,300 metres. According to an initial statement, the operation would be undertaken using the firm’s Lewek Connector vessel, a 157-metre ultra deepwater subsea construction vessel – capable of working at depths of up to 3,000m.

But the structures were finally deployed via the BOA Sub C, a smaller 138.5-metre EMAS ship.

Design of the subsea equipment was carried out by Aker Solutions, and manufactured at its Egersund and Sandnessjøen facilities.

The Aasta Hansteen field itself is located in the Norwegian Sea, 300 km west of Bodø. Recoverable reserves stand at 47 billion cubic metres of gas, in addition to some condensates. As such, it is one of Statoil’s flagship development projects and includes the largest SPAR platform in the world. Plans were approved by Norway’s Ministry of Petroleum in 2013, and production is now expected to come on line in 2017.

Above: The Aasta Hansteen concept Left: Model of the rig itself. When built, it will be the largest SPAR platform in the world

The platform will tie into the 480-km Polarled pipeline, which will carry gas from the field to the Royal Dutch Shell-operated gas plant at Nyhamna, on the Norwegian west coast.

According to Statoil, “the risers transporting the gas from the seabed to the platform and further to Polarled will be pure steel which will be first of its kind on the Norwegian Continental Shelf [NCS]. The hull will be fitted with storage for condensate. The condensate will be loaded to shuttle tankers at the field.”

Pipe-laying for Polarled began in March and is scheduled to be completed in August of this year.

Gas discovery ESMA’s installation marks another key breakthrough in the project, building on the additional Aasta Hansteen gas discoveries reported in March and April.

Exploration at Snefrid Nord yielded estimated volumes of 31-57 million barrels of oil equivalent, while drilling at Roald Rygg indicated an additional 12-44 million boe. All told, the discoveries equal around 25% of the Aasta Hansteen recoverable volumes, Statoil said.

Statoil senior vice president for exploration, Irene Rummelhoff, said that both would now be evaluated for future tie-in to the Aasta Hansteen infrastructure.

NEWSBASE

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Karoon in talks with Petrobras on developing oil hub Australian independent Karoon Gas is in talks with Petrobras about developing a hub to service their assets in the Santos Basin offshore Brazil.

Karoon wants to cut development costs for its assets in the basin by co-operating with the state-run Brazilian giant, which has giant oil and gas finds nearby.

Karoon’s managing director Robert Hosking said that a larger development hub established in partnership with third parties could be viable for the development of its Kangaroo and Echidna fields.

“There’s quite good potential for quite a large oil-in-place [OIP] development after we finish our appraisal drilling,” he told The Australian Financial Review. Karoon believes it can take advantage of systems that will be positioned around its find by Petrobras to develop its own Piracuca find, the Sabia-1 well and the Bauna and Piracaba fields, which were formerly known as Tiro and Sidon.

Other options include commissioning a FPSO for Kangaroo and Echidna in partnership with consortium’s junior shareholder Pacific Rubiales.

The Brazilian fields will be the first brought into production by Karoon and it is keen to do so at as low a cost as possible.

Karoon will also look to take advantage of the constriction in the services sector, which has been caused by E&P companies cutting back spending in response to the oil price crash. “Because it’s a distressed market now worldwide, we are looking at redeployed assets, for example, a redeployed FPSO. The labour market is getting cheaper, the labour

is getting cheaper; we see there’s a lot of cost savings for us,” said Karoon’s COO Ed Munks.

Citigroup has estimated the combined development costs of Kangaroo and Echidna at US$43 per barrel.

Edited by Ryan Stevenson ryans@newsbase.com

ExxonMobil starts up Kearl expansion ahead of schedule ExxonMobil said on June 16 that production had started ahead of schedule at its Kearl oil sands expansion project in Alberta. The C$9 billion (US$7.4 billion) expansion is anticipated to eventually reach production of 110,000 barrels per day of bitumen, doubling Kearl’s overall capacity to 220,000 bpd. The project is thought to have access to roughly 4.6 billion barrels of resource and is due to be operational for over 40 years.

Kearl is located about 75 km northeast of Fort McMurray and is operated by ExxonMobil’s Canadian affiliate, Imperial Oil. “Completed ahead of schedule, the project benefited significantly from Imperial’s ‘design-one/build multiple’ approach, ExxonMobil’s expertise in project planning and execution, strong relationships with Alberta-based contractors, and lessons learned from the Kearl initial development,” said Imperial’s chairman and CEO, Rich Kruger, in a news release.

The first phase of the project saw a C$2 billion (US$1.6 billion) cost overrun, reaching C$12.9 billion (US$10.6 billion) as a result of issues that included trouble getting

Oil sands in Alberta, Canada

NEWSBASE

Korean-built modules through Idaho and Montana, the Calgary Herald reported.

“The project benefited significantly from Imperial’s ‘design-one/build multiple’ approach” The expansion was the last major construction phase for the project, but Imperial had been planning to carry out further work on the existing facilities to push output up to 345,000 bpd by 2020.

However, the company said on June 17 that it was delaying this next expansion sometime beyond 2020.

The Kearl expansion is one of several projects that have begun or will be starting up this year. These are expected to eventually add about 300,000 bpd, or 15% to Alberta’s oil sands production, which reached nearly 2 million bpd at the end of 2014. The others include ConocoPhillips’ Surmont Phase 2, Husky Energy’s Sunrise Phase 1 and Imperial’s Nabiye Cold Lake project, the Calgary Herald said. In the longer term, though, there are still concerns about the low oil price environment hitting production growth. The Canadian Association of Petroleum Producers (CAPP) recently lowered its 2030 production forecast by 1.1 million bpd from a year ago.

The Kearl expansion is anticipated to take about a year to reach capacity.

Edited by Anna Kachkova annak@newsbase.com

ADNOC cuts opex, maintains R&D spend Government-owned Abu Dhabi National Oil Co. (ADNOC) has directed its various operating companies to reduce operating expenditure (opex) by 10-15% in light of lower world oil prices and hence revenues.

Spending on research and development (R&D) remains unaffected, however.

The statements support both anecdotal reports from oilfield services companies of being increasingly squeezed on price and, at the same time, the series of partnerships entered by ADNOC with international oil companies (IOCs) since the start of the downturn June 2014 focused on technological development.

Yasser Saeed al-Mazrouei, ADNOC’s deputy director of exploration and production (E&P), acknowledged the opex reduction request during a speech in Abu

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Dhabi on May 24, while claiming staff numbers would be unaffected. His words merely confirm observations from oilfield services providers over the past year of lower oil prices – and the 10-15% average reduction appears relatively modest, in light of the fact that Saudi Aramco is widely reported to be demanding that suppliers cut prices by up to 30%.

UAE-based rig manufacturer Lamprell, which relies heavily on business in Abu Dhabi, issued a profit warning in January with the explanation that the firm anticipates “intense competition with a large number of players chasing fewer projects, leading to increased pressure on margins.”

Fortunately for companies relying on ADNOC for a significant proportion of work, the firm has so far largely delivered on its promise to maintain capital expenditure on key projects – with tendering continuing since last June, albeit more slowly than anticipated in some instances, and awards made on major upstream schemes such the development and expansion respectively of the Mender and Al-Dabbiyah fields.

The UAE is among Riyadh’s few allies among global producers in the determination to maintain crude supply levels in defence of long-term market share, and has reiterated commitment to the longstanding goal of raising national output to 3.5 million barrels per day by 2017, from around 3 million bpd, with the latest Baker Hughes rig count data indicating no reduction in drilling activity.

Al-Mazrouei was emphatic that R&D spending would be unaffected by the revenue slump and as such would continue on a trend of year-on-year increases: “Within the R&D [element], we were not asked to drop any budget,” he said. “We don’t have a specific figure but I can tell you that we did not have any limitations … This is the eleventh year …

We’ve never had a cap.”

His colleague Ahmed al-Hendi, senior vice-president at Abu Dhabi Marine Operating Co. (ADMA-OPCO) – which handles the bulk of the emirate’s offshore production – elaborated in a presentation at the same event on the balance between brownfield and greenfield-related R&D, which he said stood at around 70:30, reflecting ADNOC’s focus on deploying enhanced oil recovery (EOR) technologies at existing fields in pursuit of a 70% recovery rate. The global average is around 35%.

Al-Hendi pointed to a recent R&D tie-up with France’s Total and the local Petroleum Institute to improve mapping of carbonate reservoirs. In October 2014, ADMA-OPCO

also signed a deal with super-major BP to develop new water-flooding EOR technology tailored to the emirate’s fields.

Edited by Ian Simm ians@newsbase.com

Agotnes jobs on the line as Aker re-jigs labour capacity Norway’s Aker Solutions announced on June 11 that 120-150 positions at the company’s Agotnes subsea services facility could be affected as it seeks to adjust the plant’s workforce capacity. The company is attempting to respond to a decline in activity in the Norwegian market, which saw compatriot Statoil also move to rationalise labour expenditure last week.

Aker anticipates the adjustments will come through normal employee turnover, reassignments to other parts of the company, and dismissals.

“Our Norwegian subsea services unit has had a slow start to the year as oil companies reduce spending and delay some projects,” said Per Harald Kongel, head of Aker Solutions in Norway, “This makes it necessary for us to adjust capacity in this area.”

Agotnes was established by Aker in 1994, when it had just seven employees. Today around 950 staff populate the 25,000 squaremetre operation, which includes an onshore engineering department aimed at providing “solutions for safe and efficient subsea projects,” and a subsea equipment testing and maintenance workshop.

It has previously been singled out as one of Aker’s “Centres of Excellence” for its role in subsea operations and services.

Aker tried to sound a confident note last week, stressing that the company is “expanding internationally,” while being “well-positioned” in certain subsea markets.

But statistics show times are changing for the firm’s outlook.

Africa accounted for 37% of Aker’s 48 billion kroner (US$6.1 billion) order backlog at the end of 2014, compared with 30% of orders destined for Norwegian projects.

The firm had around 8,000 subsea personnel employed by the end of 2015’s first quarter, with around 3,000 of these positions based in Norway.

NEWSBASE

Furthermore, Norway’s market slowdown was responsible for a fall in Maintenance, Modifications and Operations (MMO) revenue by 5% to 2.5 billion kroner (US$321.4 million) during the first quarter, a drop only partially offset by Aker’s growth on the international stage.

In March, Aker began the task of identifying 300 positions to cut in its MMO department, so there could yet be a further sting in the company’s rationalisation drive.

Edited by Ryan Stevenson ryans@newsbase.com

Chevron calls for more Vaca Muerta competition An early entrant in Vaca Muerta, Chevron said last week that more competition was needed to put Argentina’s biggest shale play into mass production.

Argentina already has skilled labour along with pipelines, hydrocarbon treatment plants and other infrastructure in place, what is needed now is more companies to ramp up drilling in the play, said Chevron’s general manager of business development for exploration and production in Africa and Latin America, Carlos Aguilera.

“Argentina has an opportunity not to be wasted,” Argentine daily LM Neuquen quoted Aguilera as saying at an industry event in Houston.

“Argentina has a great advantage that other countries do not have, both in the quality of human resources and in the infrastructure for energy distribution,” he said at the event organised by the American Chamber of Commerce in Argentina, the Argentine Oil and Gas Institute and the University of Rio de la Plata Foundation.

“We are committed to the country, but we need more companies to join,” Aguilera added. “Competition is vital as a factor for generating a true shale revolution that will accelerate the development of the play.”

Chevron, in partnership with Argentina’s state-run YPF, was the first company to begin factory mode production in the Vaca Muerta play.

In the first quarter of this year, the two were producing 42,000 barrels per day of oil equivalent, mostly of the light crude in demand at the country’s refineries. It is the

page 38

first shale oil to be produced outside North America.

Other companies such as ExxonMobil, Total and Royal Dutch Shell entered the market later and are still working toward their first production pilots.

To attract more companies and speed up drilling, Aguilera said: “[The] economic, social and legal conditions must be created to ensure the sustainability of the business over the long term.”

Argentina’s government has started to adapt and has increased wellhead prices, offered fiscal and financial incentives for increasing production and exports as well as for importing rigs and other equipment.

But one major hurdle that remains is companies’ ability to send profits out of the country, which is still difficult. Currency stability is also needed, so too a reduction in the country’s 30% inflation rate, which boosts labour and input costs.

There also needs to be more credit at lower interest rates, which requires Argentina to settle fully a US$100 billion default that has locked the country out of financial markets.

By most estimates, US$5-12 billion per year must be invested to develop Vaca Muerta and the country’s other unconventional resources.

Edited by Anna Kachkova annak@newsbase.com

Marine bunkering without infrastructure Australia’s SeaRoad Shipping has developed a means to handle LNG bunkering at ports with no direct infrastructure for LNG refuelling, the company’s marine manager, Dale Emmerton, has said.

The design features three LNG road tankers connected to a permanent fuel manifold on a newbuild LNG-powered vessel, which can be changed out following every round-trip voyage, he said. The tankers will be secured to the vessel in special loading bays on the weather deck with multiple twist locks, he told Maritime Executive.

The LNG road tanks can therefore be loaded onto the vessel during normal loading operations, allowing for refuelling with locally available LNG.

InnovOil

Steel cutting for the new ship is set to start this September at Germany’s Flensburger Schiffbau-Gesellschaft shipyard.

SeaRoad’s vessels currently burn heavy fuel oil, which is sourced overseas and imported into Melbourne by a single company for resale and delivery to the vessels.

An expectation that Australia will join other developed countries in banning the use of heavy fuel oil in coastal waters, where SeaRoad’s vessels trade, persuaded the company to look at means of using LNG, Emmerton said. LNG is also available locally from multiple sources and is seen as a cleaner and more reliable energy source, he said.

“Australia has significant reserves of natural gas which should also ensure security of supply into the future,” he added.

The global market for LNG bunkering looks set to grow substantially, with Boston Consulting Group predicting in March that LNG will become the “marine fuel of the future,” accounting for up to 27% of the bunkering market by 2025.

The industry received another boost early this week with news that cruise giant Carnival has signed a multi-billion dollar contract with The Meyer Werft to build four “next-generation” LNG-powered cruise ships with the largest guest capacity in the world.

Although the company did not provide details on its bunkering strategy, it said the vessels would be the first in the cruise industry to use LNG in dual-powered hybrid engines that power the ship both in port and on the open sea. Carnival described LNG as “the world’s cleanest burning fossil fuel” and the new vessels as a “major environmental breakthrough.”

Edited by Ed Reed edreed@newsbase.com

SOCAR to upgrade existing refinery units Azerbaijan’s national oil company (NOC) has declared its commitment to improving and modernising domestic refining capacity, unveiling plans to spend US$1.2 billion to upgrade its only oil-processing enterprise.

The State Oil Company of Azerbaijan Republic (SOCAR) has dripped out news about its plans over the past few months.

It has stated that it wants to improve existing refining facilities and to produce NEWSBASE

July 2015

higher-quality fuels. Now it may be moving towards securing outside investment for the project. “Recently, we have received concrete proposals from several companies on participation as investor-partner,” said Tofig Gahramanov, SOCAR’s vice president for strategic development. “Taking into [account] these proposals, we are negotiating with potential partners. If these negotiations end successfully, the next stages of the projects will be implemented with the investor-partner company.”

Gahramanov did not name any potential partners.

He said, though, that the investment programme would generate about US$700 million per year in additional income.

Azerbaijan has only one oil-processing enterprise. It is based on the 160,000 barrel per day Heydar Aliyev refinery, built in 1953.

Earlier this year, the plant was merged with a 239,000 bpd facility previously known as Azneftyag as part of a campaign to streamline SOCAR’s operational structure.

Both refineries are located in Baku.

SOCAR is also on the lookout for investors to help it construct a new refining and petrochemical complex outside the capital. It has said that it wants to raise US$17bn to build the facility, which is due to begin operating by 2020. (See: Azerbaijan discusses refinery project with potential investors, page 9.)

In the meantime, though, SOCAR intends to upgrade its existing processing units. Rovnag Abdullayev, the head of the company, told reporters on June 3 that a new bitumen unit would be built at the Heidar Aliyev refinery. “In connection with the move to merge the two Baku refineries, we are modernising the plant,” he said. “It is planned to construct another bitumen unit with the capacity of 400,000 tonnes per year, which will allow [us] to cover increasing bitumen consumption.”

Abdullayev further stated that SOCAR intended to sell some of Azneftyag’s primary units. The company will also build additional facilities at the Heidar Aliyev refinery, he said. “In the first stage, it is planned to construct the new bitumen unit [and] a unit for production of diesel fuel with the capacity of 3 million tonnes per year, as well as a catalytic cracking unit,” he noted.

These projects will increase the plant’s throughput capacity by 30,000 bpd, he added. n Edited by Jennifer de Lay fsuogm@gmail.com

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July 2015

InnovOil

What next …?

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

If you would like to learn more about how Glori Energy’s MEOR technology could extend the life of your field, contact Daan Veeningen on +1 713 237 8880 or at sales@glorienergy.com If your offshore asset is in need of an innovative subsea water injection solution, get in touch with Seabox’s Torbjørn Hegdal, at Torbjorn.Hegdal@nov.com If the cutting-edge completion technology of Hammerhead™ could help you push your business into ultradeepwater, contact Baker Hughes Representative Kelcie Wooten on +1.832.975.6037 To learn more about carbon capture and storage (CCS) in the North Sea and further afield, contact SCCS director and Professor of Carbon Capture & Storage, Stuart Haszeldine on +44 (0) 131 650 0294, or at stuart.haszeldine@ed.ac.uk If you would like to make an enquiry regarding the Attension High Pressure Chamber for Biolin Scientific’s Attension Theta system, please call Maiju Pöysti on +358 (0) 4 09 022010 or maiju.poysti@biolinscientific.com To learn more about the work of the International Research Institute of Stavanger (IRIS), call +47 51 87 50 00 or email firmapost@iris.no For enquiries regarding the Magna Subsea Inspection System™, contact Oceaneering International on +1 (713) 329-4500

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page 41

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

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