Oil Review Africa 5 2013

ORA 5 2013 Cover_cover.qxd 09/10/2013 14:31 Page 1

■ Geology - p38 ■ Gas - p40 ■ E&P - p42 ■ Technology - p52

Volume 8 Issue Five 2013

www.oilreviewafrica.com

Africa

Covering Oil, Gas and Hydrocarbon Processing

Europe m10, Ghana CD18000, Kenya Ksh200, Nigeria N330, South Africa R25, UK £7, USA $12

Lukoil eyes African expansion Renewed output growth for Angola New interest in South Africa’s offshore prospects Developing global expertise with a local focus Paints and coatings Drivers for tanker design Well integrity data management Drilling fluid selection

Ernest Nwapa, executive secretary, Nigerian Content Development and Monitory Board. See page 24.

Movers and shakers in Nigeria’s oil industry

REGULAR FEATURES: ■ News ■ Contracts ■ Events Calendar ■ IT update ■ Company profiles ■ Products & Innovations

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S01 ORA 5 2013 Start_Layout 1 22/10/2013 14:58 Page 3

■ Geology - p38 ■ Gas - p40 ■ E&P - p42 ■ Technology - p52

Contents

Volume 8 Issue Five 2013

www.oilreviewafrica.com

Africa

Covering Oil, Gas and Hydrocarbon Processing

Europe m10, Ghana CD18000, Kenya Ksh200, Nigeria N330, South Africa R25, UK £7, USA $12

Lukoil eyes African expansion Renewed output growth for Angola New interest in South Africa’s offshore prospects

Columns Industry news and executives’ calendar

Developing global expertise with a local focus

4

Paints and coatings Drivers for tanker design Well integrity data management

Analysis

Drilling fluid selection

All about gas and Africa

8

Gas usage is up but the pace of growth has slowed. Africa’s attractions as an investment location remain strong as conventional new discoveries are made.

Ernest Nwapa, executive secretary, Nigerian Content Development and Monitory Board. See page 24.

Country Focus

Movers and shakers in Nigeria’s oil industry

REGULAR FEATURES: ■ News ■ Contracts ■ Events Calendar ■ IT update ■ Company profiles ■ Products & Innovations

Nigeria

Working on the West African Gas Pipeline.

18

While Nigeria’s oil production remains dominated by the big international joint ventures, there is change in the air. The emergence of a host of small but ambitious and growing - indigenous companies is changing the look of the sector.

Angola

28

Angola readies for renewed ouptut growth as upstream investment continues to flow in and hopes rise regarding the corrmmerciality of its subsalt ultra-deepwater acreage.

South Africa

34

The oil and gas boom sweeping Africa has not bypassed South Africa completely and international oil companies are showing greater interest, particiularly in offshore prospects.

Geology News and developments

38

A round-up of recent geological and geophysical activity from around the region.

E&P Developments

42

Editor’s note THE CHANGING GLOBAL oil market is currently putting Nigeria's oil and gas sector on its toes as the country struggles to maintain its hold as the sixth exporter of oil in the world. While Nigeria’s oil production remains dominated by the big international joint ventures, there is an emergence of a host of small but ambitious indigenous companies, who are changing the look of the sector With an anticipated additional 400,000-bpd refining and petrochemical plant, Nigeria, no doubt is on the verge of becoming self-sufficient in meeting her domestic petroleum requirements, Further south, Angola is readying for renewed output growth as upstream investment continues to flow in and hopes rise regarding the commerciality of its subsalt ultra-deepwater acreage; and even further south there is new interest in prospects offshore South Africa.

In this issue we are also looking at new technologies particularly at coatings for offshore vessels, new tanker designs and integrity data management.

The latest exploration and prodcution news from around the region.

Technology Training

52

The route to developing global expertise with a local focus.

Paints and coatings

56

56

On board an FPSO, one of the areas of high concern for an owner is the selection of coatings for the water ballast tanks.

Cold applied vessel linings take the heat.

Ships and tankers

63

All naval architects are looking to design smarter, greener, safer and cleaner ships, reducing emissions to meet stricter environmental controls.

Integrity data management

66

Expro’s SafeWells well integrity management software can be used to monitor well integrity performance, send real time reports, highlight problems and prompt remedial actions.

Drilling fluid selection

69

A system with improved technical performance was necessary to drill more demanding, high angle and extended reach wells in East Africa.

Information Technology From the wellhead to the rooftop

76

BP chose free space otics to provide reliable high-speed connections between its various offices in Cairo.

Coatings provide a critical path to reducing corrosion on offshore structures.

Managing Editor: Zsa Tebbit - Zsa.Tebbit@alaincharles.com Editorial and Design team: Bob Adams, Hiriyti Bairu, Lizzie Carroll, David Clancy, Andrew Croft, Prashanth AP, Ranganath GS, Kasturi Gupta, Rhonita Patnaik, Genaro Santos, Nicky Valsamakis, and Ben Watts Publisher: Nick Fordham

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Africa

Covering Oil, Gas and Hydrocarbon Processing

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Oil Review Africa Issue Five 2013 3

Industry News & Events

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Executives Calendar 2013/14 OCTOBER 2013 The Ghana Energy Local Content Forum North African Downstream Summit NOCs & Governments Summit

21-22 21-22 28-30

ACCRA TUNIS LONDON

www.hialphaevents.com www.wraconferences.com www.nocs-governments.com

LONDON DAR ES SALAAM ABIDJAN LAGOS DOHA YENAGOA NIAMEY NIAMEY LUANDA CAPE TOWN

www.eliteic.net www.cwc.com www.cwcgog.com www.nape.org.ng www.cmtevents.com www.ncipnc.com www.ogtfafrica.com www.ogtfafrica.com www.aiogace.com www.petro21.com

Pre-salt Development West Africa Congress 2013

JOHANNESBURG

www.pre-salt-west-africa-2013.com

Offshore West Africa The Africa Oil & Gas Summit

ACCRA LONDON

www.offshorewestafrica.com www.africaoilandgassummit.com

Floating LNG Nigeria Oil & Gas 2014 Tanzania Local Content 2014

LONDON ABUJA DAR ES SALAAM

www.smi-online.co.uk wfww.cwcnog.com www.tanzania-local-content.com

The East Africa Oil & Gas Summit 2014

DAR ES SALAAM

www.eastafrica-og.com

NOVEMBER 2013 Angola Recruitment Summit East African Local Content for the O&G Industry GOG 2013 NAPE 2013 International Conference 8th LPG Trade Summit 3rd Practical Nigerian Content Natural Resources Development 16th Africa Oil Gas Mine Trade & Finance Angola Intl Oil & Gas Conference & Exhibition 2013 Africa Oil Week

1-3 5-8 6-8 10-14 18-20 19-21 20-23 20-23 25-26 25-29

DECEMBER 2013 11-12

JANUARY 2014 21-23 27-28

FEBRUARY 2014 17-18 24-27 26

MARCH 2014 27-28

Readers should verify dates and location with sponsoring organisations, as this information is sometimes subject to change.

SPE Offshore Europe looks ahead to the next 50 years SPE OFFSHORE EUROPE 2013 in Aberdeen celebrated its 40th birthday by staging its biggest and best conference and exhibition to date.

This year’s theme was “The Next 50 Years”, representing the continuing success story of the industry in terms of future production and the strong supply chain, which was confirmed by the scale and magnitude of this year’s event.

More than 63,000 people attended the four-day show, an increase of more than 25 per cent on the 2011 event. A record-breaking 1,500 plus organisations were exhibiting in the six exhibition halls which this year covered an expanded floor space of 27,217 sq m – the equivalent of eight football pitches.

Twenty-two operating companies took stands this year, the largest representation of operators ever to take part, and 262 companies were exhibiting for the first time. The event also provided a valuable showcase for SMEs and many new young companies which had the chance to demonstrate their innovative technologies and products to an international audience.

Vasyl Zhygalo, senior exhibition director, Reed Exhibitions, said the 40th anniversary of the event had been a fantastic success.

“Our conference and exhibition have been successful in equal measure. There has been an outstanding line up of top industry speakers from global operators and service companies and from government with standing room only at many of the key addresses and presentations. We’ve also been overwhelmed at the response from exhibitors many of whom have been queuing to sign up for 2015.

SPE Offshore Europe is held every two years at Aberdeen Exhibition and Conference Centre (AECC). The next event will take place 8-11 September 2015.

4 Oil Review Africa Issue Five 2013

Pre-salt development in West Africa WEST AFRICA'S EMERGING pre-salt reservoir characteristics, salt layers, and water depth represent major challenges to drilling, completing, and producing commercially; but the potential to recover large carbonate reserves is immense and worth the investment. To gain return on this investment, operators simply need a calculated and highly informed approach to well design to optimise drilling and production while reducing safety risks in these substantially challenging plays.

Marius Pika, assistant operation director, Perenco, will lead the well planning and design chapter at the Pre-Salt Development West Africa Congress 2013, examining the most effective well design in light of drilling, completions and safety challenges to ensure optimum oil recovery.

Libya's o&g exhibition set against strong market recovery FOLLOWING THE SUCCESS of Oil & Gas Libya 2013, plans for the sixth event in the series - Oil & Gas Libya 2014 - are set for 12 - 15 May 2014 at the Tripoli International Fairground under the joint patronage of Libya’s Ministry of Oil & Gas and National Oil Corporation (NOC).

Confidence in Libya’s oil and gas sector has grown in line with the new wave of optimism which is prevalent following the recent democratic elections.

The strong recovery in oil and gas production is a reflection of Libya’s energetic plans for huge economic development which is backed by long-term budgets totalling US$500bn over the next 25 years. This will be spent on the regeneration and construction of the country’s infrastructure immediately starting with the upgrading of existing vital services such as telecommunications, power, water and transportation, all of which are sectors vital to Libya’s oil and gas industry growth. www.oilreviewafrica.com

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Industry News & Events

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Successful O&G networking forums in Lagos

Ghana names new oil minister

CRIPPS SEARS HAS long been associated with oil & gas, natural resources and infrastructure recruitment in Africa and invited senior executives and HR professionals to attend two round table events in Lagos to discuss hot topics within the oil and gas industry.

Country and regional managers in addition to country HR and regional HR professionals from investing exploration and production and service companies in Nigeria were invited to attend the forums.

GHANA’S PRESIDENT, JOHN Dramani Mahama, has named finance and energy specialist Alexander Mould as head of the state-run Ghana National Petroleum Corporation (GNPC), according to a report.

The appointment of Mould, who was director of downstream regulator National Petroleum Authority, takes immediate effect, energy ministry spokesman Edward Bawa told Reuters.

Mould replaces Nana Asafu-Adjaye, who served for five years as managing director of the GNPC, which holds a 13.6 per cent stake in the West African nation's flagship Jubilee offshore field.

No reasons were given for Asafu-Adjaye's departure, the news wire said.

Ghana became an oil producer in December 2010 with reserves at the Jubilee field estimated at up to one billion barrels. It expects full-year 2013 production of 95,000 bpd.

Tullow Oil, Kosmos Energy and Anadarko Petroleum are some of the other partners at the Jubilee field.

Between 1985 and 1994 Mould was an adviser at the GNPC in charge of marketing. He had previously worked at Standard Chartered Bank Alexander Mould. and Union Bank of Switzerland in New York.

The key themes discussed during these talks were: 6 The challenges to growth and the challenges of resourcing indigenous players.

6 Human capacity development challenges to comply with local content laws.

6 PIB challenges.

6 Attracting new investment to the Nigerian oil and gas industry.

6 Security and community issues in Oil producing areas and it's implication on production.

The forums were very well attended by individuals from both operator and service company organisations headquartered both in Nigeria and those outside of Africa investing in to Nigeria.

Mike Cripps, managing partner commented: "It is so exciting for us to be able to contribute at the front end of energy, natural resources and infrastructure developments and to be able bring companies together who face common challenges and share ideas to create solutions".

The forum closed with many of the attendees agreeing that meeting with other members of the same industry was a useful exercise and looking forward to the next forum due to be held, again in Nigeria, very soon.

The next HR Nigeria Networking Forum will take place in November 2013.

Asco secures US$100mn deal in Tanzania

Lloyds Register to acquire Senergy

OILFIELD SERVICES PROVIDER Asco has won a major contract in Tanzania to further the group’s international expansion drive.

Valued at US$100mn, the three-year agreement to provide supply base services to BG is the largest yet for Asco’s Middle East and Africa (MEA) division.

The contract will be operated out of the East African port of Mtwara and will employ more than 100 local people.

The win comes just three years after Asco set up its MEA business from an office in Oman.

Euan Lockhart, head of the division, said the new contract would give the company a firm foothold in East Africa.

“Slowly but surely, we have been building our reputation across the region,” he said. “This contract gives us an excellent foundation from which to grow our business.”

In addition to BG, Asco will also provide warehousing, vessel loading, pipe yard storage and facilities management to Statoil, Petrobas and Ophir.

The four operators are all involved in deep-water exploration off the coast of Tanzania.

“Asco has undergone major international expansion over the two years and we now operate in four key regions – Americas, Europe, MEA and Australasia,” group chief executive Derek Smith said.

“This contract is our largest in the MEA region, and gives us a tremendous boost as we continue to build our profile and reputation in this part of the world.”

LLOYD’S REGISTER (LR) has announced a significant investment in global services company Senergy to create an industry-leading offering - from the reservoir to refinery and beyond.

The deal will see LR and Senergy provide a unique and comprehensive portfolio of services to the upstream sectors of exploration, production and transportation through to refinery and beyond.

The combined business will also provide a life of field services from inception to decommissioning and offer unparalleled opportunities for technical and consulting staff to work with leaders in the industry by providing cutting edge services to customers.

Senergy will continue to operate as an independent company for three years, by which time LR will have acquired the balance of its shares.

However, Senergy will become a member of the Lloyds Register Group and will work with LR to provide a broad service portfolio to the oil and gas and broader energy market. LR will have representation on the board of Senergy.

LR provides independent assurance and expert advice to companies operating high-risk, capital-intensive assets in the energy and transportation sectors. Helping clients to ensure the quality of construction and operation of critical infrastructure, from ships and oil platforms to power plants and trains, it also provides business assurance services it helps companies manage their systems and risks across a wide range of sectors.

Formed in 2005, Senergy applies expertise and technology to assist the development and management of oil and gas fields and alternative energy projects. Its suite of core technical services centre on subsurface, well engineering and operations, site survey and geo-engineering, facilities development solutions and power engineering which are complemented by software and training products.

John Wishart, energy director at Lloyd’s Register said: “The investment in Senergy further expands our range of technical assurance services to the oil and gas sector, building on the complementary capabilities we have built up through the acquisitions of West Engineering, ModuSpec, ODS, and Scandpower. The combined entity is now the industry’s leading provider in supporting safe operations in the discovery of new energy resources.”

6 Oil Review Africa Issue Five 2013

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DEEPWATER DRILLING AND performance improvement specialist Exceed has established new companies in Canada and Ghana on the back of recent contract wins and is in the process of setting up entities in Angola and the Middle East.

Exceed established an impressive track record as a performance improvement specialist before diversifying to launch the industry’s first project management team to focus solely on drilling projects in deepwater. The last 12 months have

involved growth and diversification of both the performance improvement and deepwater divisions of the company in response to international client demand.

The investment in a new enterprise in Ghana is driven by a high degree of confidence in the growth of the region following the announcement of the TEN deepwater field development offshore Ghana and other emerging opportunities in the Gulf of Guinea.

With an initial investment of circa

US$100,000, Ghana is a strategic decision for Exceed while offering a business-friendly operating environment.

Whilst establishing an international footprint, Exceed’s Performance Improvement division has also branched out into new arenas. Work secured recently by the division includes the Talisman Sinopec project on a North Sea platform and supporting a world first deepwater rigless well stimulation campaign for a Ghana-based client.

AGR Well Management wins award in Guinea Bissau

NORWEGIAN GROUP AGR has secured a contract with Svenska to deliver well management services for the Swedish oil company's drilling campaign offshore Guinea Bissau.

The contract involves provision of full well management and associated services, including drilling engineering and planning, supply chain management and operations support for the drilling campaign on Svenska's operated shallow water blocks 2 and 5A licences, otherwise known as Sinapa and Esperanca.

Starting during the final quarter of this year, the programme is for a minimum of one firm well with the option of two additional exploration wells dependant on results (rig contract allowing).

The sequence length could therefore range from 45 days (dry hole case) to up to 180 days. This will be further clarified once the rig contract is tendered and the rig available is known.

Jan Hagen, vice presient of Svenska said: “This programme shows Svenska’s continuing commitment as operator with its co-venturers to maintain active levels of exploration offshore Guinea Bissau.”

Ian Burdis, vp UK and West Africa, said of the award: "AGR is pleased to be working with Svenska on this exciting project.

"This is an important award and in conjunction with other recent contract wins, strengthens AGR's position as the premier provider of well management and associated services in North and West Africa."

The Svenska project is the latest in a number of long-term contracts secured by AGR, which is enjoying growing world-wide demand for its well management services.

www.oilreviewafrica.com

Oil Review Africa Issue Five 2013 7

Industry News & Events

Specialist expands into new global markets

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Analysis

Gas usage is up but the pace of growth has slowed. Africa’s attractions as an investment location remain strong as conventional new discoveries are made.

All about gas

and Africa E NERGY DATA COMPILED by BP* shows that the rate of growth of global gas consumption is falling. But the world’s reliance on conventional supplies from both North and sub-Saharan Africa remains a key feature of a vitally important business nevertheless.

Part of the reason for the rise in all-forms energy consumption slowing to just over 1.8 per cent last year was that most prices remained high, despite the increase in diversity of sources, including unconventional gas. Huge low-cost US shale supplies were of course the principal new feature impacting on the business, but any pricelowering effect from this elsewhere, including here in Africa where power generation is so gasdependant and other commercialisation difficult, remains to be seen.

However local suppliers, dealing in the conventional piped and liquefied forms of what is still the world’s favourite fuel, need to be aware that regional trends in gas use are continuing to diverge significantly. Natural gas provided just under one-quarter of the world’s traded energy last year, the multinational says. All the net growth in global all-forms consumption took place in the ‘emerging’ economies; in fact China and India alone accounted for nearly 90 per cent. OECD consumption dropped by 1.2 per cent while that of the emerging economies, some African ones included, grew by 4.2 points.

The net result was that both consumption (and therefore output) reached record levels for all hydrocarbons in 2012. So prices for natural gas rose with oil in both Europe and Asia despite the growing impact of all that low-cost hydraulicallyfractured fuel being used in North America, which continues to remain (almost) entirely in physical terms within that fortunate continent.

The bottom line is therefore that the outlook for African suppliers in general continues to remain excellent despite the USA’s shale-gas windfall. And the prospects for the independents-led East of this key energy-exporting region look particularly good.

However the time-honoured index-linking of international gas and oil prices may be coming under threat as the size of the resource base expands.

After their 2nd Summit Meeting in Moscow in July the Gas Exporting Countries Forum said they intended to “Uphold the fundamental role of longterm gas contracts and continue to support gas pricing based on oil/oil products indexation.” GECF includes Algeria, Equatorial Guinea, Egypt, Libya and Nigeria as members.

In detail, global use of gas grew by 2.2 per cent in 2012, with Africa, North America and above all

8 Oil Review Africa Issue Five 2013

Massive offshore gas discoveries in East Africa are catapulting the region into a major player in the global energy arena.

The bottom line is therefore that the outlook for African suppliers in general continues to remain excellent despite the USA’s shale-gas windfall.

China and Japan heading the continuing upward trend. But at the same time any increase in international trade, by both pipeline and gas carrier, was exceptionally weak at just 0.1 per cent yearon-year. And global business in liquefied natural gas in volume terms fell for the very first time ever, by 0.9 per cent.

“LNG’s share of global gas trade declined slightly to 31.7 per cent” the BP report says; a big fall in European imports being almost entirely responsible. The implications for Africa of this disturbing trend, where liquefaction is so often seen as the optimal means of commercialising vast quantities of otherwise stranded gas, exacerbated by ambitious developments in Australia, are disturbing.

Huge growth in global gas resources The massive growth in global gas resources has filled the media headlines throughout the year, almost entirely because of unconventional activity in general and the expected impact of the newly-commercialised technology of hydraulic fracturing in particular.

The scale of reserves is a different matter. So it

is only in North America that shale gas can really be fully and accurately accounted for in the equation as yet; elsewhere it remains largely a case of “who knows and who allows?” And if this new form of gas (which will bring necessary onshore processing adaptations with it) is found in the sort of quantities that are being talked about now (more than doubling world reserves) it is anything but certain how much can be actually exploited commercially.

And for most of Africa the unconventional resource situation remains unknown; the exciting recent discoveries on the Indian Ocean fringe being all about conventional supplies in relatively shallow waters that will be relatively easy to develop by non-members of the IOCs club.

Therefore outside North America the impact of the so-called “fracking revolution” remains to be seen even though so much is being heard about it.

But potential gas exporters without long-term supply contracts in the bag do need to keep their eyes on the ball.

On the global production front the main news has been the USA’s 4.7 per cent increase last year; globally growth was a mere 1.9 per cent. Some other countries did even better, such as Saudi Arabia (11.1 per cent, mostly conventional). But here in Africa the increase was only 2.1 points, and most of this was accounted for by the rebound in supplies from Libya alone. In the region’s biggest single gas-producing nation (Algeria) output actually fell. The Nigerian industry did exceptionally well to push up its marketing of

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Energizing a refinery to protect its most valuable resources.

People.

Follow the Charge Safe, dependable power is critical to a successful refinery operation.

Equally critical is the safety of the crews working in these highly powered environments.

That’s why Valero, a leading manufacturer of petrochemical products, made personnel safety a top priority when they chose to upgrade one of their more complex, 24/7 process refineries. And they chose Eaton to help.

Valero demanded proven arcpreventative motor control center technology to lower the probability of electrical shock and reduce incident arc flash energy during

eaton.eu/followthecharge/m4 ©2013 Eaton. All rights reserved.

»

maintenance. Eaton rose to the challenge.

For this critical project, Valero chose Eaton’s FlashGard ® motor control centers (MCC). The first MCC designed specifically to prevent arc flash. Unlike conventional designs, FlashGard allows for closed-door maintenance operations. Providing a much-needed barrier to protect personnel and equipment from the dangers of arc flash.

The heavy power capabilities and safety systems needed to fuel tomorrow’s world, calls for solutions today. Eaton is already there.

Analysis

S02 ORA 5 2013 News_Layout 1 22/10/2013 15:05 Page 10

associated and non-associated supplies by 6.2 per cent in volume terms.

This country is now amongst the world’s five largest national producers of LNG and a very experienced player in an increasingly fraught business. It has proved reserves of more than 180tcf and perhaps a further 500-600 waiting in the wings. Less than 20 per cent of its annual output is used domestically, even though only a hopelessly-inadequate 4GW of electric power is currently available. Enough gas is thought to be available to increase this to 5GW by the end of the year, with an optimistic ceiling of 10GW being aimed at within 2015/16.

Abuja’s Gas Master Plan Under Abuja’s Gas Master Plan of 2008 gas-based industrialisation targets are being pursued at the same time as power generation, at such secure and dedicated locations as the brand-new Ogidingbe Industrial Park in Delta State. Around 2,000 cars are already reported to be running around the southern states with new-form

Bardex wins contract for Moho Nord TLP BARDEX CORPORATION HAS won a contract from South Korea's Hyundai Heavy Industries (HHI) for a BOP (blowout preventer) cage and drilling riser skidding system for operation on the Moho Nord TLP (tension leg platform) which HHI is building for Total for operation offshore Congo-Brazzaville.

"The Bardex skidding system comprises two hydraulic gripper jacks each of 75 tonnes push-pull capacity powered by a 30 hp (horsepower) hydraulic power unit, approved for use in ATEX Zone 1 hazardous area," Bardex said.

HHI reported earlier this year that it had clinched the US$700mn order for a TLP from Total. The company will carry out engineering, procurement, supply, construction and commissioning of the TLP to be deployed in Moho Nord field, 80 km off the Republic of Congo's coast.

compressed natural gas in their tanks, believed to be a first within the region. This is a major growth trend in the US automotive market right now, and gas-powered ocean-going container vessels are understood to be on the way.

Elsewhere, consumption-wise there were some major individual changes seen in 2012, most of which (such as in South America) have not influenced business here in Africa at all. However the 11-point increase in gas processing for local use in Algeria surprised some, although it does seem to be a logical commercial response to the general weakening in volume terms of the gas market in Europe. Gas use in this nearby region (including Eurasia), the world’s largest consuming group, was down by 2.3 per cent.

Japan’s 10.3 per cent increase was inevitably a standalone case, almost entirely due to the fall in output of nuclear-generated electricity.

LNG traders dealing with Asia did particularly well out of this development, with supplies from Nigeria alone more than doubling to 6.5bn cu m over the 2011 level. This was by far the largest

component of Africa’s liquefied gas trade last year, exceeding Algeria’s individual shipments to France and Spain on which the whole business was founded in the first place.

One of the features of the gas market is that it is very high cost, both to develop initially and to supply after that. In Qatar-pursuing Australia costs are rising fastest of all, and this is providing opportunities for Africa’s traditional suppliers, and to the potential nimble newcomers who have the resources of all those handy oil-/gasfield service companies (and in some cases Chinese NOCs) to rely on.

But gas has become increasingly important to the supermajors too, and the competition is going to be tough if the major consuming groups manage to break that long-assumed linkage with the international cost of oil. Africa is likely to be one of the key battlegrounds for building profits. ■

* ‘BP Statistical Review of World Energy June 2013’; www.bp.com/statisticalreview

2H Offshore joins Tullow team for TEN project 2H OFFSHORE, AN Acteon company, has been appointed by Tullow Oil as lead riser engineering consultancy for the delivery of the flexible riser system for its Tweneboa, Enyenra and Ntomme (TEN) field development, offshore Ghana.

The TEN development is located in the Deepwater Tano block, approximately 30 km to the west of the Jubilee field and lies in water depths ranging between 1,000 metres and 1,800 metres.

The development will consist of oil and gas production wells, water injection wells and gas injection wells. Production will be gathered through subsea manifolds and flexible risers to a FPSO. 2H will ensure the riser engineering design complies with ISO 13628-2 and provide recommendations on riser optimisation, installation and overall assurance that the risers meet the project Basis of Design (BOD) and specification.

“We are delighted to have the opportunity to work with Tullow Oil in leading an integrated riser engineering team to deliver the flexible riser system for the TEN development,” said 2H director, Hanh Ha. “Our in-depth knowledge and experience with flexible risers will enable us to develop and optimise the system to meet the project’s combined challenges of deep water, complex subsea bathometry and aggressive delivery schedule.”

New technology agreement within IEA THE GAS & OIL Technologies Implementing Agreement (GOT IA), the newest such agreement within the International Energy Agency’s (IEA) technology network, was launched recently in New York. The GOT IA will create a global dialogue, leading to a strategic vision; it will address technology gaps, business cases and roadmaps, as well as incentives and other technology drivers leading to safer and more sustainable development and use of the world’s natural gas and oil resources.

In making the announcement, Jostein Dahl Karlsen, chairman of the IEA’s Working Party on Fossil Fuels and the chairman of the new implementing agreement said, “Following the unconventional gas revolution in the United States, gas and oil technology has become a key driver at the heart of world energy developments. Therefore, the global gas and oil community has a growing role to play in international concerted action responding to the major challenges facing energy developments in the 21st century. The Gas & Oil Technologies

10 Oil Review Africa Issue Five 2013

Implementing Agreement stands ready to work with multilateral organisations, governments, industry, research institutions, academia and non-government organizations to support innovation that moves the world toward a more sustainable, efficient and affordable energy future for all.”

The executive committee of the GOT IA selected GE Oil & Gas as the operating agent of the new agreement to provide administrative and secretariat duties.

Markus Becker, global government affairs and policy leader for GE Oil & Gas said, “Technology is the key to providing the world secure, abundant and affordable gas and oil resources in a safe and sustainable manner.

At GE Oil & Gas, we believe that addressing the technology gaps, regulatory and policy drivers in a collaborative and open manner will lead to outcomes that support the optimum development and use of those hydrocarbon resources.” www.oilreviewafrica.com

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Recruitment

E-mail is the standard method of approach within the O&G industries these days.

We look at the best ways to use it in the initial filtering stage.

Online

recruitment I

T IS THE nature of the energy businesses that online applications for new positions are now the norm. Technicians and other professionals are usually too busy or remotely located to use any other means. And skilled personnel move around the world rapidly, rarely being available for face-to-face interviews except by local agencies.

Dealing efficiently with the conventional e-mail application is covered here. Some recruiters go further and delve into the world of social networking to corroborate and fill out the details.

This is generally not advised. First, there may be unwanted legal implications. Second, many good applicants for new positions work in countries where social networking is strictly controlled, or even banned altogether; particularly in the Middle East. Not relying on the system at all means that a level playing field is created.

Never overlook substance in CV Online agencies tell job applicants repeatedly to ensure their cv or resumé is as perfect as possible.

Sometimes the result is that presentation takes precedence over substance. And what they often fail to point out is that most applications are ‘scanned’ quickly on screen (just 10 seconds or so) and rejected immediately; only a selected few go on to the next stage and are read thoroughly. That’s when the covering letter (essential) is inspected too.

So, in the absence of an application form, the skilled recruiter knows to look out for the following features: 6 Conventional presentation as an attached Word document in .doc or .docx format; beware of fancy material within time-consuming pdf’s which suggests an unprofessional approach. Tidy layout is always good, with bullet points used to separate short sentences containing only relevant information. Photographs are not appropriate unless asked for.

6 Just two pages that present the essential data in a logical sequence, which varies from country to country (usually nationality/contact details/training/work experience with the latest most fully outlined first in the sequence/personal background data). There should be no surplus words.

6 Keywords such as conventional terms for previously-held standard job descriptions (and country locations) presented early within each section, as this shows that the applicant knows how rapid filtering works, relying heavily on the use of conventional search terms.

12 Oil Review Africa Issue Five 2013

The PIB will obligate all IOCs operating in the country to hire and train more Nigerians.

6 A brief personal statement which shows what an

6

6

6

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ambitious applicant could bring to this individual vacancy, separating them positively from the rest. Many applicants send precisely the same details for all positions. The covering letter should display this attention to detail too.

Pay particular attention to spelling, but make allowances for the fact that many will not be using their first language. Linguistic abilities are always an asset.

Consistency matters! Has the applicant explained any (long) employment gaps? Does the document ‘hold up’ (ie, do different sections complement one another)?

Some recruiters say that a few relevant numbers help, eg, a record of how the applicant performed previously. Obviously for a technical position this is hard to justify, but even a note about size of work team helps. Such data tends to be memorable because it is tangible. If it backs up a claimed achievement, all the better.

Supply of references is inappropriate at the initial online application stage, but willingness/ability to supply them is vital (often stated in the covering letter, which should always be retained).

Finally, use your instincts but back up the rejection of an 7/10 scorer with a second look!

And remember that an applicant who manages to fill the gap between modesty and bragging is usually worth considering seriously.

A case in point about online recruiting arises from Nigeria’s long-awaited Petroleum Industry Bill, which is expected to completely overhaul the oil and gas sector in sub-Saharan Africa’s most important producing country.

The renewed focus will be on increasing the sourcing of local content, most importantly of skilled staff; this is already well under way following the recent implementation of the Nigerian Content Act. Restructuring of the industries themselves, and of the fiscal regime, will increase substantially the need for staff who have to be hired (or at least initially filtered) by electronic means as NNPC and its components become “clear commercial entities.”

Search for Nigerian staff looks costly These will cover oil, gas and national asset management activities with partial deregulation downstream; at least one will be a joint venture with a foreign partner so duplication of tasks seems likely. Therefore the costly search for more Nigerian staff looks certain to increase. Fortunately this is already one of SSA’s most online-capable countries.

In addition the PIB will obligate all IOCs operating in the country to hire and train more Nigerians and to take on a greater number of local contractors.

It all adds up to a predictable increase in the number of online applications which will have to be handled by the commercial entities themselves, and the many jobsearch agencies they employ.

Effective e-mailing will help oil the wheels. ■

www.oilreviewafrica.com

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Company Spotlight

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Amid the steadily falling production in the domestic market, Russian Lukoil is continuing accelerating its foreign expansion.

Russian Lukoil

eyes African expansion F

OLLOWING ITS RECENT announcements about the plans to increase its presence in the Middle East region in the coming years, the company has also declared that the Western Africa region will also continue to be among the priority regions for its further foreign development in the long-term.

Implementation of African projects will take place as part of Lukoil’s global strategy for the development of shelf projects. According to Vagit Alekperov, head of the company, by 2021 the company plans to invest US$11bn in the implementation of its offshore projects, with particular attention to be paid to Africa and Brazil.

At the same time none of these funds will be invested in the development of the domestic shelf in the Arctic region, which, in accordance with the Russian legislation, still remains the monopoly of state-owned companies, such as Rosneft.

At present the development in West Africa remains in the list of three most important areas of the company’s international expansion in the coming years, along with the West Qurna-2 project in Iraq and some projects in Uzbekistan.

According to Yegor Sobolev, head of department of strategic management of Lukoil Overseas, Lukoil’s operator of foreign projects, the company estimates the volume of hydrocarbon reserves in the Western Africa is currently at least four billion tons of oil equivalent, being located on eight blocks. According to the company’s estimates, successful operations in Western Africa in the long term will allow it to increase total volume of oil production by about 10 per cent.

He also added that already this year the company plans to drill three wells in Côte d'Ivoire and one well in Sierra Leone.

In the case of Côte d'Ivoire, the company considers this country as top-priority for its further development in the African continent.

This is reflected by its latest moves. In June this year Lukoil acquired 65 per cent stake from the private Nigerian company Taleveras Energy in the CI-504 project on the Côte d'Ivoire offshore in the Gulf of Guinea.

The project involves exploration, development and production on the block. Among the other participants of the project are also Taleveras with the 25 per cent stake, and the Petroci Holding with 10 per cent.

The CI-504 block is located close to the existing Baobab field, while its area is estimated at 399 sq km. From the south, CI-504 it shares a border with CI-205 block, which is also operated by Lukoil. At

14 Oil Review Africa Issue Five 2013

Lukoil spud its first well in an undrilled portion of a deep-water block off Sierra Leone with the Erik Raude.

According to the company’s estimates, successful operations in Western Africa in the long term will allow it to increase total volume of oil production by about 10 per cent. the same time, in additon to these blocks, the Russian company currently remains the operator of CI-101 and CI-401 blocks of the country’s shelf.

Lukoil has been operating on the Côte d'Ivoire shelf since 2006 after signing an agreement with the US Vanco Energy to acquire 63.33 per cent of the CI-101 and CI-401 blocks.

The production of the first oil on the Côte d'Ivoire shelf by Lukoil officially occurred at the end of 2011 on the CI-401 block. This year the company is going to spend about US$400mn on drilling of exploratory wells near the newly discovered reserves. According to the company, the resources of the CI-401 block are estimated at 5.6bn barrels. The volume of reserves of other blocks have not been determined.

Lukoil hopes that further development of the Côte d'Ivoire shelf will be associated with discovery of high quality sandstones, containing high-gravity oil and gas condensate.

Plans to speed E&P activities Lukoil plans to speed its exploratory and production activities in Côte d'Ivoire, as the country’s government has recently expressed its dissatisfaction, regarding the regular delays in the development of its shelf projects, even threatening revocating of licenses in case of further delays.

At the same time, in addition to Côte d'Ivoire, Lukoil plans to accelerate its expansion in other African countries, and in particular Ghana and Sierra Leone.

In the case of Ghana, the company plans to continue development of the Block Cape Three Points Deep Water (CTPDW), a stake in which was acquired by it on July 2006. At present its share in the project amounts to 56.66 per cent, with 28,34 per cent owned by PanAtlantic (formerly Vanco), while the remaining 15 per cent is owned by the state-owned GNPC. Under the terms of the contract the development of the block will take place in two stages - exploration and development. In 20102011 several promising oil and gas fields were discovered, as a result of drilling three deep-water exploration wells. A new stage of exploration drilling is planned for late 2013.

More active development in Egypt At the same time Lukoil is ready for more active development in Egypt, as part of the local longterm Meleiha project, which is one of the first

www.oilreviewafrica.com

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Company Spotlight

S04 ORA 5 2013 Lukoil_Layout 1 22/10/2013 15:15 Page 16

Further expansion in the region will take place through the strengthening of co-operation with local players.

Lukoil and Vanco have entered into contracts to drill four wells in CTPDW block, including two exploration wells on new structures and two appraisal wells on the Dzata structure.

foreign projects of the Russian company. It entered into the project as part of the Russian-Italian joint venture Lukagip in 1995. Currently, the share of Lukoil in the venture is 24 per cent. Other participants of the Meleiha project are Eni (56 per cent) and Mitsui (20 per cent). Proven oil reserves in the block are estimated at more than 30mn boe.

According to Lukoil plans, during the next few years, the company will focus on the development of several oil fields in Egypt, which have been discovered in recent years, among which are the North and Gavaher Nada (2007), Arcadia (2010), Emery Deep ( 2012) and North Rose (2013).

Finally, in Sierra Leone Lukoil currently remains the operator of the SL-5-11 project, which is a deep-water block and part of a Sierra Leone Liberia geological basin, and where several large oil fields have been discovered in recent years. Lukoil acquired its 49 per cent stake in the project in July 2011 from Oranto Petroleum.

As part of the 30 years’ contract, the company plans to drill one exploration well this year, which will requre investments in the volume of up to US$100mn. Drilling is scheduled to begin in August 2013. The amount of investments in the next phase of exploration works will depend on the results of drilling.

According to Andrew Kuzyayev, head of Lukoil Overseas, this year the company plans to invest about US$600mn in the implementation of its projects in Western Africa.

West African region remains promising According to Gregory Birge, a senior analyst of Investkafe, one of Russia’s leading analyst and research agencies in the field of oil and gas, despite Lukoil’s mixed results of exploratory drilling in the region, the Western African region remains very promising for the company, in terms of further increase of production in the near future.

According to his predictions, in case of further

16 Oil Review Africa Issue Five 2013

major discoveries (comparable to Ghana’s Jubilee field and Côte d'Ivoire’s Baobab) Lukoil may significantly increase production at the western African shelf already in 2015-2016, while its daily production in the continent may reach the level of 70,000-80,000 barrels.

At the same time analysts also warn that despite big potential of the Western African region for Lukoil, the company must take into account not only geological risks, associated with the development of African fields, but also geopolitical threats. In 2011 Lukoil was forced to stop operations in Côte d'Ivoire for a certain period of time due to the destabilisation of the geopolitical situation in the country, which resulted in significant losses to the company. Currently the political situation in the majority of western African states remains unstable, which poses a threat to the company’s business in the region.

Another concern may be related to high costs of implementation of local projects. For example, French Total recently estimated its total costs for the development of its oil filelds in Congo at about US$1bn, due to their big depth and high prices for the rental of drilling vessels.

However, despite this, Lukoil’s management

believes that Africa will remain in the list of the world’s most priority regions for the company’s foreign development both in case of oil and gas in the coming years, as the situation in the domestic Russian market remains unfavourable. The latter reflected by the lack of new promising oil fields, as well as an inability to get access to the Russian shelf, despite the company’s numerous attempts in recent years to get this right. According to Kuzyayev, the company also believes that further expansion in the region will take place through the strengthening of co-operation with local players, which will be in the form of joint ventures and alliances.

Interestingly, several months ago Lukoil attempted to attract Rosneft, another Russian leading oil company and its main rival for the joint development of the African continental shelf.

Lukoil made an official proposal to Rosneft to exchange part of its African assets on Rosneft offshore projects in the Russian Arctic.

However this offer was declined by Rosneft, as, according to sources in the latter, it has more attractive options for exchange and in particular those, which involve sharing of assets with its US partner ExxonMobil. Another reason for rejection was Lukoil’s partial participation in its African projects and the fact that the company does not have 100 per cent interest in any of these projects.

At the same time, instead of co-operation with its main rival Lukoil, there is a possibility that Rosneft may enter the African continent in partnership with Italian Eni. At the end of last year Rosneft announced its plans to build a pipeline in Africa, with the aim of supplying fuel to Zimbabwe, Zambia, Malawi and Botswana. It has also not ruled out the possibility of participation in development projects in the region with Eni and in particular in Mozambique.

According to sources in Rosneft, Mozambique is a very promising region, but more in terms of gas production. For example, Eni stated that gas reserves at its projects in the country reach two trillion cu m. ■

Africa Oilfield unit inks deal with Weatherford AFRICA OILFIELD LOGISTICS' 49 per cent-owned subsidiary Ardan Risk & Support Services has signed a contract with Weatherford Drilling International to provide camp management, catering and medical support to its 120 person camp in Turkana, Kenya.

Ardan has won a number of contracts with international oil & gas, drilling, engineering and exploration companies operating in East Africa, and is advancing its strategy of becoming the leading provider of support services and logistics in Africa.

Africa Oilfield director Andrew Groves said: "Ardan continues to build its reputation as the premier support services and logistics company in the East African region and is rapidly growing its client list, particularly with leading international oil & gas and associated engineering companies including, Africa Oil Corp, Global Geophysical, Tullow Oil and BGP Seismic. www.oilreviewafrica.com

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SGS as the world’s leading inspection, verification, testing and Certification Company, we provide competitive advantage, drive sustainability and deliver trust. Recognised as the global benchmark for quality and integrity, we employ over 70,000 people and operate a network of more than 1,350 offices and laboratories around the world. We are continually pushing ourselves to deliver innovative services and solutions that help our customers move their businesses forward.

SGS have their operations established in Nigeria since 1957, we have a local content workforce of over 90% indigenous Nigerians and we are fully committed to “The Nigerian Content Policy� as promulgated by The Federal Government of Nigeria.

SGS Inspection Services Nigeria Limited board of directors consists of 50% Nigerian nationals and the Company has 50% Nigerian shareholding.

S05 ORA 5 2013 Nigeria_Layout 1 22/10/2013 15:19 Page 18

Nigeria

While Nigeria’s oil production remains dominated by the big international joint ventures, there is change in the air. The emergence of a host of small but ambitious - and growing - indigenous companies is changing the look of the sector. Here’s a round-up of who’s who in Nigeria’s fast-changing oil and gas industry.

Movers and shakers in Nigeria’s

oil industry 2013 Production track record: Conoil Producing Ltd Conoil Producing is one of Nigeria’s largest homegrown oil firms, with both domestic and foreign assets. The company is the operator of six Niger Delta blocks and has established a solid track record as a producer through three main hubs, OML 136, OML 59 and OML 103, working alongside elite partners such as Total. It also holds a 25 per cent equity stake in a block in the highly prospective Nigeria São Tomé & Principe Joint Development Zone (JDZ) (Block 4).

Into the big leagues: Oando Energy Resources With a stock market listing in Toronto, Oando Energy Resources is one of Nigeria’s better known oil companies abroad. It is currently targeting the acquisition of the local assets of ConocoPhillips.

The US group agreed last year to sell its onshore assets after 46 years of operation in Nigeria to Oando for US$1.79bn. The deal will catapult Oando into one of the nation’s biggest producers.

Conoco’s fields were producing around 43,000 bpd last year and have proven reserves of 213mn barrels of oil equivalent.

Nigeria has an abundance of natural resources, especially hydrocarbons.

An emerging producer: Amni International Petroleum Development Twenty-years-old this year, Amni International is working with French oil giant Total to exploit gas reserves from the IMA field, where it recently installed a newer and bigger FSO (floating storage and offloading) vessel. It is also a partner in the producing Okoro/Setu fields with UK-listed Afren plc, where development work is ongoing. Average gross production here is about 17,815 bpd, with Amni holding a 50 per cent interest.

A regional focus: Atlas Oranto Petroleum International Ltd A privately owned, independent Nigerian oil company based in Lagos, Atlas Petroleum was launched more than a decade ago by its owner and chairman, entrepreneur Prince Arthur Eze. The company has established a pool of upstream interests in the West African region, including Equatorial Guinea, the Côte d’Ivoire as well as Nigeria and works with a number of notable technical partners.

Deepwater investor: Dangote Equity Energy Resources The oil and gas arm of Nigeria’s powerful Dangote Group, Dangote Equity Energy Resources is a strategic investor in a number of upstream oil and

18 Oil Review Africa Issue Five 2013

Things are now moving fast for Emerald Energy Resources after international partner Oryx joined the OML 141 project team. gas projects. In Nigeria, this includes a small interest in Block 315 partnering Statoil and Petrobras. It also holds equity in two blocks (Blocks 1 and 3) in the Nigeria São Tomé & Principe Joint Development Zone (JDZ).

Downstream, the group is at an advanced stage of project development for a huge refinery. It also holds interests in power generation.

Stepping on the gas: Emerald Energy Resources Ltd Emerald Energy is the operator of block OML 141 a large under explored license area in the prolific Niger Delta with five identified prospects - which it was awarded back in 2000. Things are now moving fast for the Lagos-based company after international partner Oryx joined the OML 141 project team in 2011. Emerald now retains a 33 per cent stake in the block, with another local firm, Amni International, also a partner. Oryx has been

on the fund raising trail this year to help finance the development of the block. Seismic acquisition is planned for the latter part of this year, with a well to follow.

Agbami rights: Famfa Oil Founded in 1991, Famfa Ltd - later re-named Famfa Oil - was incorporated in September 1991 and assigned the leasehold rights to block OPL 216 two years later. In 1999, drillers discovered the giant Agbami field. Now in production, the field has estimated in place reserves of up to two billion barrels of crude oil. The block sits approximately 350 km south east of lagos and 110 km offfshore Nigeria in the central Niger Delta.

Onshore and offshore: Sahara Energy Field The upstream exploration arm of the Sahara Group, which boasts a span of energy interests. Since it began operations in 2004, Sahara Energy Field has compiled a portfolio of domestic projects: OPL 274 western onshore Niger Delta; OPL 286 in deepwater Nigeria; OPL 284 in deepwater Nigeria; and the Tsekelewu marginal field (OML 40).

A true pioneer: Dubri Oil Company Nigeria’s first indigenous oil producer, Dubri Oil is a real industry pioneer. Founded in 1987, the

www.oilreviewafrica.com

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S05 ORA 5 2013 Nigeria_Layout 1 22/10/2013 15:19 Page 20

Nigeria

The joint ventures

Pan-African focus: Afren plc UK-listed Afren plc has emerged as one of Nigeria’s fastest-growing producers in recent years. It has production from various fields including Ebok and Okoro/Setu, plus a host of other exploration projects. Average gross production at Ebok is around 33,884 bpd, while at Okoro/Setu it is around 17,815 bpd. The company holds a 50 per cent stake in each, alongside indigenous partners.

Afren is also active across the wider African region.

OML30 update: Shoreline Natural Resources In the last few months since the first interview with ‘Oil and Gas Review Africa’, Shoreline Natural Resources can be said to be on a positive track.

The company has seen an increase in production, with an average of 45,000 barrels now being produced on a daily basis. This it associates with the introduction of some of its short and medium term work programme activities having kicked in; an example of this would be the introduction of some new gas-lift compressors to the asset, to improve oil recovery.

Within the fourth quarter of this year, Shoreline expects more capital investment leading to a further increase in production by the end of 2013.

Another milestone reached is in its financing structure. Previously it was funded using a shortterm bridge finance loan. This has now been replaced by a long-term reserved based lending facility (RBL), involving a consortium of local and international banks.

All in all the company is still very excited about OML30, its continued prospects, and any possible opportunities that it may bring. Its goal is still to develop not only this asset, but also nurture and build Shoreline Natural Resources into one of largest oil and gas companies out of Nigeria working into Africa.

Elcrest joint venture: Starcrest Nigeria Energy Ltd A subsidiary of the Chrome Group of companies, Starcrest Nigeria Energy is focused on the Gulf of Guinea, predominantly Nigeria. Most significantly, it is a partner with UK-listed Eland Oil & Gas in a joint venture company, Elcrest Exploration and Production (Nigeria) Limited. Elcrest has an agreement to acquire a 45 per cent of an onshore lease OML 40 from SPDC, a block that has production history, booked developed and undeveloped reserves, infrastructure for production and export for 30,000 bpd. Starcrest holds 55 per cent of Elcrest shares, with the rest is held by Eland.

African ambition: South Atlantic Petroleum One of Nigeria’s ambitious new breed of explorers, SAPETRO now has an upstream footprint that spans both sides of Africa. After cutting its teeth in West Africa - with a slice of production from Nigeria’s large offshore Akpo field - the company has now joined the great gas search in eastern Africa with exploration rights in ever popular Mozambique. SAPETRO holds interests in deepwater Nigerian blocks OML 130 and OPL 246, where its partners include Total, Petrobras and the China National Offshore Oil Corporation (CNOOC). The Akpo field has produced more than 220mn barrels of condensate to date. ■

One of Nigeria’s ambitious new breed of explorers, SAPETRO now has an upstream footprint that spans both sides of Africa. privately owned Lagos company operates block OML 96, where it has now been producing for more than 25 years. Oil is treated at the company's Gele Gele flow station and barged down the Osse River to Chevron's Escravos terminal for export. Dubri Oil was also the first private Nigerian company to spud its own exploration well which led to the discovery of the Ovia field.

The state concern: Nigerian National Petroleum Corporation

With a stake in most of the country’s big oil fields, NNPC is perhaps the single most important producer in Nigeria. The state-owned company holds equity in all of the large oil producing joint ventures, alongside international partners like Shell, Chevron and Total. NNPC is active both upstream and downstream through a network of subsidiary firms. The company is in a state of flux, however, with the government keen to transition this huge organisation into a more open and commercial entity, emulating the success of overseas state oil concerns such as Statoil (Norway) or Petrobras (Brazil).

20 Oil Review Africa Issue Five 2013

Shell Petroleum Development Company of Nigeria Ltd The largest of the NNPC joint ventures, SPDC is led by Shell. Other partners include Elf (Total) and Agip. It has the largest acreage position in Nigeria from which it is capable of producing as much as one million bpd. Most of the company's operations are concentrated in the Niger Delta and adjoining shallow offshore areas. Civil unrest in the Delta area in recent times has meant some infrastructure and production has been closed in intermittently. SPDC has more than 6,000 km of pipelines and more than 1,000 producing wells.

Chevron Nigeria Ltd Chevron is the third-largest oil producer in Nigeria and one of its largest investors, spending more than US$3bn annually. Chevron Nigeria has assets on land, swamp and near-offshore concessions covering approximately 8,900 sq km in the Niger Delta region. The US company holds a 40 per cent stake in the joint venture with NNPC holding the balance. Chevron also has extensive interests in deepwater Nigeria. The Agbami field is one of the country’s largest deepwater discoveries; it also has an interest in the Usan deepwater project.

Mobil Producing Nigeria MPN and partner NNPC operate over 90 offshore platforms comprising about 300 producing wells with a capacity of over 550,000 bpd of crude, condensate and natural gas liquids (NGL). Mobil holds a 40 per cent stake in the venture, and NNPC 60 per cent. A series of projects could increase the current average production to above one million bpd. These include the East Area Additional Oil Recovery project which marks a major investment in a mature operation to extend field life, increase recovery and eliminate non-routine gas flaring by injecting produced gas.

Nigeria Agip Oil Company This joint venture, in which NNPC maintains a 60 per cent stake, is operated by Agip (part of Italy’s Eni group). The US’ Phillips Petroleum is another partner with 20 per cent. The JV produces mostly from small onshore fields. It too has been affected by production disruptions from attacks, spills and oil theft. Earlier this year, it suspended activities at some of its swamp fields in Bayelsa state after losing about 7,000 bpd daily to oil thieves.

Total (E&P) Nigeria Ltd A joint venture between NNPC (60 per cent) and Total of France (40 per cent). Originally called Elf Petroleum Nigeria, this joint venture changed its name in 2008 in the wake of Total’s acquisition of French rival Elf Acquitaine. Total's current upstream operated production of over 250,000 boepd in Nigeria comes from both onshore and offshore blocks (OMLs 58, 99, 100, 102 and 130). Total’s current thrust is the deep offshore blocks OPL 222 (Uka, Uran and OPL 246) which are also being developed on a systematic basis.

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Nigeria

Nigeria is an emerging gas super-power, with the world’s ninth largest gas reserves, but the nation needs to produce seven bcfd of gas to meet the 2020 target of being one of the top 20 economies in the world.

Opportunities, challenges in Nigeria’s

petroleum industry N

IGERIA HAS AN abundance of natural resources, especially hydrocarbons. It is the 10th largest oil producer in the world, the third largest in Africa and the most prolific oil producer in subSaharan Africa.

The Nigerian economy is largely dependent on oil, which supplies 95 per cent of its foreign exchange earnings.

To discuss the opportunities and challenges in the sector, the Nigerian Gas Association (NGA) at its yearly general meeting, brought stakeholders together to deliberate on several issues, such as the Petroleum Industry Bill (PIB), gas flaring and others.

Presenting the perspectives of the Oil Producers Trade Section of the Lagos Chamber of Commerce and Industry on the opportunities, challenges, and the way forward for the gas industry in Nigeria, its chairman, Mark Ward, described Nigeria as a nation with big ambitions.

According to him, Nigeria aspires to be one of the top 20 economies in the world by 2020 by developing a large, diversified, sustainable and competitive economy. “Nigeria certainly has the potential to achieve this. The nation is already delivering significant economic growth. Over the last decade, the economy has grown by more than eight per cent year on year, unfortunately, this growth has only benefited a narrow segment of its people. But, with the largest population in sub-Saharan Africa and abundant natural and agricultural resources, Nigeria has an opportunity to broaden its economic base,” he added.

Ward noted that Nigeria’s economy was not growing and diversifying fast enough to reduce poverty and unemployment for its fast growing population.

“Unfortunately unemployment has increased from 12 per cent in 2006 to 24 per cent in 2011. Additionally, with around 80 per cent of the government’s budget dependent on oil revenues, Nigeria is vulnerable to an oil price shock”, he added.

He pointed out that accelerated and diversified economic growth was critical for Nigeria to meet its vision. “A major step in the direction of diversification will be to build on the potential of Nigeria’s enormous gas reserves to power change”.

He added: “Nigeria is an emerging gas super-power, with the world’s ninth largest gas reserves. We believe these reserves can bring growth and diversification to Nigeria through more power generation, more gas-based industrial activity such as fertiliser plants, to boost agriculture and high value exports to bring revenue to the nation.

He said though the country has made some progress, the achievements were only a fraction of the potential and of what must be achieved to support Nigeria’s vision 2020.

He noted: “In terms of power generation, Nigeria has one of the lowest power consumption levels per person in the world – even when compared to similar emerging economies. Regrettably, the nation has only moved from 3GW in 1999 to 3.5GW generation today against a need for 40 GW by 2020.

This shows that immediate and dramatic action is needed to help the nation achieve its goals.

“What upstream activity is needed to support these goals? Nigeria needs to produce seven bcf of gas per day to meet these 2020 targets – the equivalent of 14 times the Utorogu gas plants. Today we produce less than one bcf to the domestic market from the largest gas reserves in Africa”.

The deputy director in charge of Gas Development at the Department of Petroleum Resources (DPR), Okpara Orjiakor, who represented the DPR director, George Osahon, said that the International Oil Companies (IOCs) were deliberately undermining the PIB to make excessive profits and urged them not

22 Oil Review Africa Issue Five 2013

Nigeria loses N735m daily to gas flaring

Nigeria aspires to be one of the top 20 economies in the world by 2020 by developing a large, diversified, sustainable and competitive economy. to go to the National Assembly to oppose the passage of the bill.

Group executive director in charge of gas and power at the Nigerian National Petroleum Corporation (NNPC), Dr David Ige, said the greatest challenge facing gas development in the country was the domination of the gas business by four or five IOCs, saying this dominance accounted for the current tension over the PIB. He said about 90 per cent of the country’s gas reserve was concentrated in the hands of these IOCs. According to him, such oligopolistic arrangement where oil majors, who were primarily centred around oil or export gas sit on the country’s gas reserves has created tension because the IOCs want the PIB to approach gas at the same level as oil.

PIB must make gas equally competitive He said the two products were different commodities, stressing that the PIB seeks to make gas equally competitive.

Ige defended the separation of the gas business from the oil business in the PIB, saying that globally, consuming nations are moving away from linking gas price to oil price.

“The task today is to delink the price of crude oil from the price of gas because there is a lot of distortion in the price of oil. So, when you use the price of oil to determine the price of gas, you will introduce a lot of inefficiencies,” he said.

Ige said the country’s projection for gas was the most aggressive projection anywhere in the world, adding that if the country achieves this projection by 2017/2018, the combined production of gas in Nigeria would translate to an equivalent of 1.5mn bopd.

He said if the country achieves four to five billion cfd domestic utilisation of gas by 2018, Nigeria would be at par with South Korea in terms of domestic gas consumption. ■

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S06 ORA 5 2013 Nigeria News_Layout 1 22/10/2013 15:23 Page 23

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Nigeria

Nigerian government was committed to the local content policy AT THE UNITED Kingdom Investment programme in Aberdeen, executive secretary, Nigerian Content Development and Monitory Board (NCDMB), Ernest Nwapa said that the Nigerian government was committed to the local content policy, whose focus areas are job creation, training and domiciliation of technical capacity and also development of facilities and infrastructure. He said there was a case for a strong linkage between manufacturing and the oil and gas industry as there is sub-optimal utilisation of locally-made goods. He said that they have adopted a two-pronged approach to stimulate a manufacturing culture and enhance the use of made-in-Nigeria goods Nwapa stated: “We want to change Nigeria’s value chain to domesticate a number of technologies in Nigeria. Most oil producing countries have learned from experience but not in the case with Nigeria. We are looking for partners that would help in technology transfer in the oil and gas industry. Investors must be ready to domesticate some equipment in our oil and gas industry. We have set up industrial parks to help with the local content development. Most investors were focusing on getting revenues from Nigeria without adding value to the country.

“It is not just about revenue, but adding value to the system in such a way that it will be a win-win situation. An equipment component manufacturing

Ernest Nwapa.

company is now a pre-requisite for companies coming to invest in Nigeria’s oil and gas industry.

The country has no plan to endanger foreign investments but manufacturing of components will be a pre-requisite for government to support. It will be a pre-requisite for local content certification.”

He said that Bayelsa and Imo states had made land available for indigenous equipment manufacturers to promote the local content policy.

According him, Shell has agreed to build a jetty worth US$10mn in Bayelsa, next to a pilot pipe mill project for steel piping.

“We are trying to organise a standard training to develop skills for host communities in the Niger

Delta. We have contacted a company to help with the supervision of the training programme. We are equally partnering PETAN to organise industrial training. Every PETAN member must have an internship programme for the people trained from the host communities. We are also encouraging international oil companies to fund Nigerian universities to engage in research and development.”

According to him, Nigeria spends US$4bn on marine vessels to export the country’s crude, and that the local content board is encouraging the foreign companies to partner some Nigerian companies to sell off some of their equities.

General manager, Shell Petroleum Development Company (SPDC), Igo Weli, said Shell was collaborating with the Original Equipment Manufacturers (OEM), since June 2012, adding that these companies were ready to establish manufacturing facilities in Nigeria.

According to him, the SPDC contractor fund is to complement the Nigerian Content fund, and that four Nigerian banks have agreed to guarantee a soft loan to local contractors. “We are working with PETAN in respect of technology development and we are ready to give long-term projects of 15 to 20 years. We are trying to encourage research development in Nigerian universities. We are already working with the Universities of Ibadan and Port Harcourt on drilling mud solution”, he said.

CAMAC starts drilling at Oyo-7

Tycoon plans Nigeria’s largest oil refinery

CAMAC ENERGY HAS an encouraging news update following its Q1 13 net loss of US$3.8mn.

The US-based exploration and production Transocean’s Sedneth 701. company owned by Nigerian business man, Dr Kase Lawal, has been informed by its partner, Allied Energy Plc that drilling operations at the Oyo-7 well commenced on 9 September, 2013 using Transocean’s Sedneth 701 drilling rig.

The drilling of the pilot hole to assess shallow hazards around the Oyo-7 location was successfully completed. The rig is being positioned over the actual Oyo-7 location after which drilling operations will continue.

Oyo-7 is expected to both significantly increase oil production from the currently producing reservoir and de-risk much of the unrisked resource potential in the field. Oyo, the first deepwater discovery in Nigeria, has been online since December 2009.

The company’s principal assets include interests in OML 120 and OML 121, offshore oil and gas leases in deep water Nigeria, which include the currently producing Oyo Oilfield. The company says it is currently pursuing further additions to its exploration portfolio in East and West Africa and was recently shortlisted in the Chevron sale.

A COMPANY RUN by Africa's richest man received a loan toward a US$9bn project that will give Nigeria its largest oil refinery and petrochemical and fertiliser complex, reducing the country's reliance on international markets.

Aliko Dangote, president of Dangote Group, signed a loan worth US$3.3bn from 12 Nigerian and international banks toward the project which will be built in Nigeria's southwest.

"At the completion of these projects we expect Nigeria to become not only self-sufficient in fertiliser and refined petroleum products but indeed to become recognised as a leading exporter of these products," Dangote said at the recent signing.

Nigeria is Africa's biggest oil producer, and is a top supplier of crude to the US, but the West African country has to import most of its fuel because of decrepit refineries unable to meet the nation's demand for gasoline due to years of mismanagement and sabotage.

The 400,000 bpd oil refinery and complex will become operational by 2016, the company said. The plant will also produce 2.8mn tonnes of urea for fertilising crops and to produce polypropylene, used to make plastics. Dangote said the company is still seeking an additional US$2.5bn in development funds to augment the US$3.5bn of its own equity put into the project. The US$3.3bn loan deal was led by Standard Chartered and Nigeria's Guaranty Trust Bank.

NUPENG (Nigeria Union of Petroleum & Natural Gas Workers) said the refinery would go a long way to ending the perennial scarcity of petroleum products and put an end to the current massive importation of products.

While commending the Dangote for the project, the union called on other private investors and the multinational oil companies to take a cue from him, especially 18 firms that were granted licences to establish refineries under the Obasanjo regime and have not made any move to live up to expectations.

24 Oil Review Africa Issue Five 2013

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Nigeria

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Breaking the monopoly of foreign players in drilling rig business SEAWOLF OILFIELD SERVICES Ltd was established in April 2007, with the objective of providing drilling and drilling-related oilfield services in the West African oil and gas market.

The company’s entry strategy was hinged on market entry through Nigeria, which contributes approximately 50 per cent of the West African drilling and drilling-related services market. SeaWolf’s entry into the Nigerian market was premised on the Nigerian Content Initiative driven by the NNPC. The company's mission is to be the contractor of choice for safe, environmentally responsible, operationally efficient, high specification, drilling services in West Africa.

SeaWolf operates the most modern and effective fleet of jack-up drilling units - including two new builds - Oritsetimeyin and Onome, that can operate in 91 m of water depth, to a rated drilling depth of 7,600 m - and Delta Queen, which can access multiple wells on a platform, without ever having to move.

In 2012 SeaWolf signed a US$140mn contract to provide its premium cantilever jack-up rig, 'JU Oritsetimeyin' to ExxonMobil for two years, starting the third quarter of 2013, following a refit to meet ExxonMobil’s safety, environment and operational requirements. SeaWolf described the contract it signed with ExxonMobile as ‘testament to how far indigenous players have come in the ownership and operation of offshore oilfield assets’.

The two other rigs - JU Onome and JU Delta Queen - were signed to Addax Petroleum and Conoil Producing respectively.

Mono Puli: a trailblazer in local content FOUNDED AND INCORPORATED by High Chief (Dr) OB Lulu-Briggs in 1992, Moni Pulo Ltd (MPL) represents a creative response to the Nigerian government's initiative to promote indigenous participation in the nation’s oil and gas industry. With its head office in Port Harcourt, Rivers State and branch offices in Lagos and London, MPL is a private, fully indigenous E&P company.

Over the years, MPL has acquired an enviable reputation as one of the most successful indigenous oil and gas explorers and producers in Nigeria.

A trailblazer in the area of local content, Moni Pulo has developed its operational efficiency to international standards and has acquired expertise as the sole operator of its asset, OML 114. This is blessed with substantial gas reserves, and negotiations are at an advanced stage with leading international companies on the way forward for actualising the organisation's gas monetisation plan. The company has also acquired three new blocks - OPL 239 in Ondo State, OPL234 in Abia/Ibom and OPL in Cross River /Akwa Ibom states.

MPL has gone a long way to ensure compliance with the Nigerian government’s gas flare out policy. Produced associated gas currently being flared will be re-injected into a dedicated reservoir for storage. An injector well for this purpose has been drilled and completed. Gas compression facilities will be commissioned in the first quarter of 2010.

The re-injection will continue until the time when the gas master plan of the company is ready for implementation.

Recently Moni Pulo signed a seismic contract with Sinopec Changjiang Engineering Services Ltd for the development of the Northern Area of OML 114.

List of Nigerian operators Nigerian Operators: Addax Petroleum: Addax Petroleum Development Nigeria Ltd Addax Petroleum Exploration Nigeria Ltd Addax Oil and Gas Nigeria Ltd Chevron: Chevron Nigeria Ltd - CNL ChevronTexaco Texaco Overseas Nigeria Petroleum Company Ltd - TOPCON Star Deep Water Petroleum Ltd Texaco Nigeria Outer Shelf ChevronTexaco Nigeria Deepwater ‘E’ Ltd ChevronTexaco Nigeria Deepwater ‘A’ Ltd Eni-Agip: Nigerian Agip Oil Company Ltd - NAOC Nigerian Agip Energy - NAE Nigerian Agip Exploration ExxonMobil: Mobil Producing Nigeria Ltd - MPNU Esso Exploration and Production Nigeria Ltd - EEPN Esso Exploration and Production Nigeria Deepwater West Shell: Shell Petroleum Development Company of Nigeria Ltd - SPDC Shell Nigeria Exploration and Production Company Ltd - SNEPCO Shell Nigeria Ultradeep Shell Nigeria Exploration Properties Alpha Ltd Total: Elf Petroleum Nigeria Ltd - EPNL Total Upstream Nigeria Ltd Independants and Local Operators: Allied Energy Resources Nigeria Ltd - CAMAC Amni International Petroleum Development

26 Oil Review Africa Issue Five 2013

Company Ltd - AMNI Cavendish Petroleum Nigeria Ltd China National Offshore Oil Corporation - CNOOC China National Petroleum Corporation - CNPC Conoco Energy Nigeria Ltd - CENL Conoco Exploration and Production Nigeria Ltd CEPNL Conoil Producing Ltd Dubri Oil Company Ltd Emeral Energy Resources Ltd Express Petroleum and Gas Company Ltd KNOC Nigerian East Oil Company Limited Korea National Oil Co KNOC Nigerian West Oil Company Limited Korea National Oil Co Moni Pulo Ltd MPL Niger Delta Petroleum Resources Ltd Nigerian National Petroleum Corporation NNPC Nigerian Petroleum Development Company Ltd - NPDC Noreast Petroleum Nigeria Ltd Ocean Energy Nigeria Inc - DEVON Oil and Natural Gas Corp Ltd Mittal Energy ONGC Mittal Energy Oil and Natural Gas Corporation Ltd Videsh NGC Videsh Oranto Atlas Petroleum International Ltd Oriental Energy Resources Ltd Pan Ocean Oil Corporation Nigeria Ltd PANOCO Peak Petroleum Industries Nigeria Ltd Petroleo Brasileiro Nigeria Ltd - PETROBRAS Statoil Nigeria Ltd Summit Oil International Ltd Sunlink Petroleum Ltd Yinka Folawiyo Petroleum Company Ltd

Marginal Fields Operators: Afren African Oil & Gas Angus Energy (USA) Associated Oil & Gas Services Ltd Bayelsa Oil Corporation Bicta Energy and Management System Ltd Britania-U Nigeria Ltd Chorus Energy Ltd Del-Sigma Petroleum Nigeria Ltd Energia Company Ltd Eurafric Energy Ltd Excel Exploration and Production Services Exile Frontier Oil Ltd Geo Energy Goland Petroleum Development Corporation Ltd Guarantee Petroleum Corporation Hardy Oil Nigeria Ltd Independent Energy Mart Resources Midwestern Oil & Gas Corporation Millenium Oil & Gas Ltd Morris Petroleum Ltd Movido E & P Network E & P Oando plc Owena Oil & Gas Ltd Pillar Oil Ltd Platform Petroleum Corporation Ltd Prime Energy Resources Ltd Sahara Energy Field Ltd Sogenal Ltd Suffolk Petroleum Services Ltd Suntrust Universal Energy Resources Ltd Walter Smith Petroman Oil Ltd

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Angola

Angola readies for renewed output growth as upstream investment continues to flow in and hopes rise regarding the commerciality of its subsalt ultra-deepwater acreage. Cost inflation could prove a headache, however, and it has raised the crude price floor Angolan producers require, considerably. Samuel Ciszuk reports.

Renewed output growth

for Angola A

NGOLA’S CRUDE OUTPUT has fluctuated rather steadily between 1.6-1.7mn bpd in the past few years, despite constant official statements that growth past the two million bpd mark was just around the corner.

The temporary plateau has proven hard to move away from, being caused by project delays in the face of an overheating Angolan project environment, resulting in skill shortages and spiralling costs. As project bottlenecks built up in the development phases, it was only a question of time before exploration spending too was impacted and the whole development pace in the country’s buoyant oil and gas industry started to slow down. Angola’s problem was and is however not as deeply structural or intractable as some other hydrocarbon producers with high hope of growth, like for instance Iraq, or Nigeria. From an oil industry perspective, contract terms and the political will to, within reason, attract investment, remain attractive and the country is not plagued by the security or political risks besetting so many other large-scale oil producers in Africa and the Middle East. Project overload and cost inflation are of course very serious problems; ultimately they are however of a passing character.

Recognising this, Asian crude buyers have been quick to snap up Angolan cargoes over the past few years, as US imports of Angolan grades have declined. Obviously, Angola had a definitive geographic benefit over other West African exporters, being closer to Asia than Nigeria and the other Gulf of Guinea producers. Angolan crudes have in particular become popular with China, where they have been well situated, quality-wise, to be attractive to many of the existing refineries. It has been a very fortunate confluence of events for Angola, as the decline in US imports stemming from its shale oil revolution happened at the same time as the need for Chinese buyers to look further afield for relatively heavy crudes the like of Angola’s. Other African producers, most notably Nigeria and Algeria, have fared worse, being too far from Asian markets and selling too light grades to look as attractive, given the higher shipping costs.

Consequentially their differentials to benchmark crudes came under significant pressure in the past two years. Still, despite the fundamental merits of geography and buyers’ crude preferences, Angola’s underlying position as a comparably stable future growth area has no doubt proven yet another attraction to Asian clients looking for new suppliers.

With this in mind, it is exciting to note that the temporary production plateau at which Angola has been stuck for some time now looks like it is giving

28 Oil Review Africa Issue Five 2013

Angola’s PSVM offshore project came on stream earlier this year.

PSVN now produces crude wholly through underwater installations, all linking up to one single FPSO vessel. way during 2013 and 2014. The country’s two million bpd production target is unlikely to be reached this year, however sometime late next year or in the first half of 2015 an output capacity just above that level looks likely. The growth will be driven by a few large deepwater projects coming onstream or ramping up this year and next, chief among them the BP-led PSVM venture. PSVM, or Plutão, Saturno, Venus and Marte, is a technically challenging ultra-deepwater development showing the way for how Angola’s increasing sub-salt ultradeepwater reserves could be tapped in the not-toodistant future. PSVM came onstream late last year and will at its peak produce 157,000 bpd of crude.

Unlike previous developments in Angola’s deepwater blocks 15, 17 and 18, the Block 31 PSVM project lacked one large dominating discovery which in its own right made development commercial. Instead, the four planet-named discoveries span a length of 34 km at the most.

Having a relatively similar size, each being below what would be considered attractive to develop

given the challenge involved, the project only started to make sense when the developing consortium (operator BP 26.67 per cent, Angola’s NOC Sonangol 45 per cent, Sinopec 15 per cent and Statoil 13.33 per cent) chose to look at the field as one cluster instead of four different uncommercial reservoirs. Recent strides in deepwater technology naturally made certain this change of perception was possible.

PSVN now produces crude wholly through underwater installations, all linking up to one single floating production, storage and offloading (FPSO) vessel. Located at a depth of around 2,000 metres, the US$14bn project is truly setting an example in subsea engineering, which is raising the hopes that the discoveries that have started being made in Angola’s ultra-deepwater subsalt acreage, particularly in the Kwanza and Banguela basins, will be possible to monetise even if new elephantsized fields are not found.

Angola’s offshore mirrors Brazil’s It has for some years now been held true that Angola’s extended offshore mirrors Brazil’s, which should mean similarly significant reserves of crude in subsalt reservoirs. The expected similarity stems from Africa and Latin America having been joined at one time, and the seabed now separating the two continents being created at the same time, when

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Angola

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BP's PSVM floating production storage and offloading (FPSO) oil vessel, 180 km off the coast of Angola.

The PSVM project could be a very timely project setting an example of how to keep costs down by tying numbers of separate fields together in all-subsea developments. the landmasses drifted apart. While it is too early to come to a final conclusion whether the two sides actually mirror each other resource-wise, discoveries on both sides so far seem to give the theory credence. Sub-salt exploration in Brazil is much more advanced, but is set to accelerate in Angola, with several wells set to be spudded between this year and up to 2015. Exploration of the reservoir rocks located below a 2,000 metre salt layer in water depths of more than 2,000 metres is however a costly undertaking. Explorers hence have an eye on what potential development could cost from the outset, before even spudding their wildcat well.

So far, few exploration programmes in the two subsalt basins have progressed far, since Denmark’s Maersk Oil, with partners Svenska Petroleum Exploration and Sonangol announced their virgin discovery in the Kwanza basin with the Azul-1 well in January 2012. A recent sub-salt discovery offshore Gabon by France’s Total has added further to excitement in the wider region, although news early September that Total also scored a sub-salt gas discovery sent shares of its partners Cobalt and Marathon – both at the time with Angolan sub-salt

interests – tumbling, demonstrating how strong concerns over commerciality investors have. More certain knowledge about the Angolan sub-salt’s commerciality is still awaiting the exploration programmes starting this year and next.

Angola LNG offers marketing possibilities Gas discoveries and the fears over their uncommerciality, is an interesting aspect, given that Angola’s first LNG venture, Angola LNG, came onstream in June this year, following an 18 month delay. The project offers a marketing option for Angola’s associated and non-associated gas, providing an avenue to improve the commerciality of otherwise marginally profitable oil fields. Indeed, the PSVM project is a case in point, allowing the development to start selling its associated gas to the liquefaction plant, making sure that the BP-led venture simultaneously can cut its flaring. Yet, concerns over high liquefaction costs and worries over potentially weakening LNG prices in the coming years are evident, as seen in the market reaction to Gabon’s pre-salt gas discovery. For all the question marks over medium and long-term oil prices, oil remains far more likely to pay for the vast exploration and development costs associated with Angola’s output growth.

A major challenge This touches on one of the main challenges to a renewed Angolan oil boom and brings us back to the problems of the country’s inflated project costs.

Should the oil price - currently supported by the large-scale outage in Libya and the considerable political risks in Syria, Egypt, Iraq, and to some

extent Iran – start to fall back in the medium term, as risks ease off and the global supply growth led by the US shale oil boom continues, the expensive Angolan projects could be at risk. Among a growing number of oil industry economists, speaking of peak oil demand has become en vogue, meaning that oil demand in developed economies has entered permanent decline, while oil demand growth rates in developing countries like China and India might not return to the peak growth rates seen in the past decade (although they likely will remain high for yet some time).

Simplified, the peak oil demand is seen as the result of “a second oil price shock” in the run up to 2008 and again in 2011-2013, as present and planned gains in fuel efficiency, energy efficiency and a switch to renewables in one way or another represent a permanent switch away from yesterday’s oil dependence.

Whether or not the argument holds true remains to be seen, but it shows that concern in the industry might be switching from a concern over insufficient supply (or at least concerns over supply bottlenecks) to concerns over large parts of the global market being in a perpetual state of shrinkage. Should this be right and the shale oil boom in the US continue, there is a risk that the most expensive subsalt exploration projects in Angola, already suffering from considerable cost inflation, could be axed before other relatively expensive projects, like the US shale oil. In the US economics of scale already exist.

Hence, the novel subsea field cluster development approach brought by the PSVM project could have been a very timely project just as the exploration starts getting underway, setting an example of how to keep costs down by tying numbers of separate fields together in all-subsea developments. It might raise the attraction of the Angolan play a bit further and help to at least somewhat contain fears of continued skill shortages and spiralling costs. After all, Angola is not the only hydrocarbon geography grappling with this problem, which even is besetting the US onshore amid its feverish boom. Then again, all the fear of the industry having to adjust to a significantly lower oil price in the years ahead could well become a moot point, as the stability of Libya and the levels of political risk in the overall Middle East show no sign of improving. Indeed, that underlines one of the key attractions of Angola - its relative stability in a rather unstable wider region. ■

GE Oil & Gas forms JV with GLS Holdings to support rapid growth in Angola’s energy sector GE OIL & GAS and the Angolan group GLS Holding have formed a joint venture, GE-GLS Oil & Gas Angola Ltd, to better support Angola’s rapidly growing oil and gas sector.

As part of the agreement, which received the approval of Angola’s National Agency for Private Investment (ANIP), the companies are planning a proposed initial investment of US$175mn to build a new manufacturing facility in Soyo, in the province of Zaire, that will supply subsea equipment to the oil and gas industry in Angola.

Dr Eugenio Neto, president and CEO of GLS Holding, and vp of the new JV, said: "GE-GLS Oil & Gas Angola Ltd intends to support the development of Angola, bringing new manufacturing and industrial

30 Oil Review Africa Issue Five 2013

technologies to the country and creating hundreds of jobs directly and indirectly. The investment represents an important contribution to the country’s "Made in Angola" initiative and, consequently, for the continued growth of Angola’s oil and gas industry. It will be a great asset to Angola’s petroleum sector and the country and its first priority will be to meet domestic demand in Angola.” The new manufacturing facility will start operating in two years.”

“The purpose of this investment is to provide the country with new production capacities, including high-tech subsea production equipment, that will create added value and technological knowledge,” said Marco Caccavale, general manager of GE Oil & Gas for sub-Saharan Africa. www.oilreviewafrica.com

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Angola

Total’s Leviathan deepwater Pazflor: a technological marvel that will drill for 20 years TOTAL'S PAZFLOR FLOATING production, storage and offloading unit (FPSO), as big as most US aircraft carriers, is what Louis Bon, the project's director, calls the tip of the iceberg.

That's because the "biggest part of the development is subsea and you don't see it," said Bon at OTC 2013. Below the massive ship is more than 260 km of pipeline and control lines that snake across the seabed. About 2,000 metric tonnes of equipment rest on the seabed.

"It's a huge investment, US$9bn, and it is in particular an offshore platform that uses new technology and equipment, specifically designed, engineered and qualified for the project," he said.

At OTC 2013 Total was honoured with the Distinguished Achievement Award for Companies for its Pazflor project. The prestigious award is awarded annually to the company that has advanced deepwater oil expertise and technology as part of a major project.

It is now more than two years that Pazflor has reached the maximum operating capacity and is proceeding as planned, which proves the reliability and robustness of the technology that we have for that development.

The platform operates offshore Angola in depths of up to 1,200 metres. Production averages 220,000 bpd and more than 45mn barrels have been produced since August 2011.

To get to that production, Total had to invent new ways of drilling underwater, including a groundbreaking subsea gas and liquid separation process.

Commonly, oil is mixed with gas and water

Repsol enters partnership with Sonangol EARLIER THIS YEAR Repsol entered into a partnership with Sonangol which will allow the company to use Repsol’s Project Kaleidoscope technology, which has also been used to make recent discoveries in Brazil and the Gulf of Mexico.

Twenty-seven Sonangol engineers will be trained to use the technology at Repsol’s technology centre in Madrid with the aim of helping them to model the Kwanza basin, an area offshore Angola which has become a hot area for exploration in recent years and which geologists see as analogous to the Santos basin in Brazil.

32 Oil Review Africa Issue Five 2013

Pazflor’s subsea separation unit.

when it is extracted. The Pazflor deployed subsea separation units (SSUs) that strip oil and gas apart at depths where human intervention is impossible. Once separated, the oil and the water is pushed to the surface by seabed Pazflor pumps. The lighter gas rises naturally to the FPSO. The subsea modules are designed to operate for a 20-year period. Bon said the SSUs had never been used before on such a scale.

"So we decided to run through a very intensive qualification programme for each of the components of the subsea separation units.

Commissioning tests were carried out in Norway and ensured functionality and simulated all steps of the installation sequence. In all 13 different pieces of equipment were tested in 56 separate qualification tests," he said.

"Strong quality assurance and quality control organisation within the Total team and contractors' teams was in place and turned out to play a crucial role."

The project also required meticulous co-

ordination at all levels.

Total teams worked hand in hand with contractors, all of whom were located on the construction site and onboard during the commissioning. Supervision of the project spanned the globe in Angola, South Korea, Norway and the US. After departing South Korea in January 2011, the Pazflor FPSO headed to its position in Angola in April 2011.

A well defined scope of work was created through extensive front-end design and engineering studies. The project also strived to work in partnership with Angola by training technicians and management personnel in forefront deep offshore technologies. Finally, drilling into a pay of almost 600mn barrels of oil required finding just the right spot.

Total's geosciences team also ensured the optimisation of well placement and maximum well quality in co-ordination with the drilling team. Within six months, all facilities, including water gas injection, were fully operational.

"One of the important achievements of the project was to manage good integration and a good relationship between the geosciences and drilling teams in order to optimise drilling", Bon said.

In August 2011 Pazflor became one of the world's largest deepwater developments.

One year after reaching its maximum capacity, the Pazflor is operating smoothly with an availability ratio of more than 97 per cent.

"We have made some new technologies and proven some new technologies to be useful in the industry," Bon said.

TWMA wins Angola’s first oil & gas processing contract TWMA, THE LEADER in integrated drilling and environmental solutions for the international onshore and offshore oil and gas industry, has become the first company to be awarded an offshore processing contract in Angola.

The agreement, worth up to US$35mn, will see TWMA pioneer the concept of offshore processing in this rapidly developing but environmentally sensitive frontier, through the design, installation and operation of tailored solutions on-board a new-build drillship to support a major global operator’s drilling campaign.

Underlining TWMA’s global growth plans, this latest contract - with duration of up to five years - will see the company

establish a new onshore support facility in Luanda and is expected to generate up to 50 new jobs in Aberdeen and Angola by the end of the year.

Ian McGillivray, global sales executive at TWMA, said: “As new and frontier energy regions around the world develop, it is critical that operators are aware of the differing environmental legislation and standards, and as such carefully plan how they intend to deal with drill cuttings and associated materials.

“This is an exciting project for TWMA and will see us operate for

the first time in a country where there is an evolving environmental policy regarding the treatment and disposal of drill cuttings. As a result we are engineering our proven solutions into a new-build rig design to recycle drill cuttings and fluids at source.”

TWMA is currently working with clients in the UK, Norway, Egypt, Cameroon, Abu Dhabi, Canada and the United States; treating and recycling in excess of 100,000 tonnes of drill cuttings and associated fluids annually.

“Having assisted operators in their global drilling campaigns for many years our innovative solutions have earned the trust of the industry and are capable of meeting even the most stringent environmental regulations,” added Rob O’Neill, sales director at TWMA. www.oilreviewafrica.com

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South Africa

The oil and gas boom sweeping Africa has not bypassed South Africa completely and international oil companies are showing greater interest, particularly in offshore prospects.

New interest in

offshore prospects W

ITH LIMITED KNOWN reserves, South Africa relies heavily on crude oil imported from the Middle East and Africa to meet the country’s current consumption of some 680,000 bpd.

These imports contribute significantly to the current account deficit with only a small proportion of the country’s requirements produced domestically

by Sasol and from PetroSA’s Mossel Bay project.

In general, refined petroleum products including petrol, diesel, paraffin, aviation gasoline and liquified petroleum gas are produced by refining crude at the country’s refineries, by converting coal to liquid fuels and gas to liquid fuels (Sasol), and by turning natural gas into liquid fuels (PetroSA).

However, the oil and gas boom sweeping Africa has not bypassed South Africa completely and international oil companies are showing greater interest, particularly in offshore prospects.

According to research by PwC, more than US$1bn will be spent on exploration with about 10 companies having been granted exploration licences. ExxonMobil and Anadarko have acquired deepwater rights on the east coast and BHP Billiton, Cairn India and Sunbird Energy on the west coast.

South Africa is estimated to have the fifthlargest shale gas reserves in the world. Many hurdles remain, but the first step towards development took place in September last year when the government lifted its moratorium on shale development. Coal bed methane reserves are estimated to be between 10 and 30tcf.

On the refining front, PwC says PetroSA is still evaluating the construction of its proposed refinery at Coega, and that Euro V standards may bring considerable change to the refinery landscape as it could cost US$4bn to meet the required standards.

Proposed new legislation In the light of the country’s dependence on oil imports, there has been much criticism of the proposed Mineral and Petroleum Resources Development (MPRD) Bill that is intended to replace current legislation of the same name. At public hearings on the bill in September, oil company executives and financiers complained that it would make South Africa’s oil and gas sector less attractive.

Amongst the industry’s concerns are proposed requirements that government appoints two directors to company boards, the sector be subject to unknown beneficiation requirements, and the dissolution of the oil and

34 Oil Review Africa Issue Five 2013

International oil companies are showing greater interest, particularly in offshore prospects.

From a practical point of view it would be recommended that South African legislators also consider providing for exceptional circumstances. gas regulator, the Petroleum Agency SA, and the takeover of its functions by offices of the Department of Mineral Resources.

These and other changes led to calls for the oil and gas sector to be exempted from the bill.

Others drew comparisons with Uganda, which is also amending legislation in order to keep up with the oil rush.

MPRD Amendment Bill South Africa’s MPRD Amendment Bill was introduced into Parliament on 21 June this year, while in Uganda, the Petroleum (Exploration, Development and Production) Act 2013 (PEDPA) came into force on 5 April, repealing the Petroleum (Exploration and Production) Act cap 150 (PEPA).

According to Lizel Oberholzer, head of oil and gas at pan-African corporate law firm Bowman Gilfillan: “In South Africa and Uganda, amongst other countries, the method of applying for petroleum rights or licences, the significance of the

regulator, state participation, and the duration of rights or licences have come under scrutiny.”

Under PEPA in Uganda and the MPRD Act in South Africa grants were made by way of direct application to the minister. This position has changed under the new legislation, which provides that areas open for bidding in exploration licensing will be announced in the government gazette.

However, in Uganda the minister may in exceptional circumstances receive direct applications. These circumstances include instances where no applications have been received in response to invitation to bids, and instances where areas are adjacent to existing licensed reservoirs.

Oberholzer said that, “From a practical point of view it would be recommended that South African legislators also consider providing for exceptional circumstances as is case is in Uganda.”

Another difference is that, while under the MRPD Amendment the independent regulator is disbanded in South Africa, PEDPA moves closer to international best practice and introduces the Petroleum Authority Regulator (PAU). “It is unclear why the South African legislator is moving away from international best practice,” said Oberholzer.

Although neither the MPRDA nor PEPA provided for state participation in petroleum licences or rights, in practice such participation was negotiated in the petroleum agreements. This position has

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South Africa

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changed under the MPRD Amendment Bill and PEDPA which make provision for state participation.

She added: “However, in both countries the percentage of state participation is not specified in the legislation. Since there have been significant discoveries in Uganda, this uncertainty may be acceptable to oil companies. However since no significant discoveries have been made in South Africa such uncertainty may scare investors away”.

In Uganda the initial period of the petroleum exploration licence was reduced from four years to two years under PEDPA, while in South Africa the initial period of the exploration right was increased from three years to five years.

“In practice it can be very expensive and time consuming to mobilise a drilling rig, and particularly in the case of Uganda, difficult to gain access to land. As a result, the exploration period of two years might be insufficient to complete work programmes.

“African Governments should learn from each other to establish regulatory frameworks that are in line with international best practice and encourage investment in the continent,” said Oberholzer.

Willing to take risks PwC says Africa currently supplies about 12 per cent of the world’s oil and boasts significant untapped reserves estimated at eight per cent of proven reserves globally. These reserves have

36 Oil Review Africa Issue Five 2013

increased in the last two decades and the trend is expected to continue.

“Overall, the booming oil and gas industry is seeing greater interest in all regions, including frontier states such as Namibia, Togo, Liberia and areas where exploration and production had been diminishing over the last few years. This includes countries such as Ghana, Côte d’Ivoire and South Sudan. The crown jewels are, however, the new players on the east coast, particularly Mozambique and Tanzania.

“Significant gas finds in excess of 127tcf in Mozambique have created the potential for another African super player.”

PwC estimates that in sub-Saharan Africa only about 30 per cent of 2,900 identified oil and gas blocks are licensed, with many new opportunities, especially for exploration and production companies that are willing to take risks.

Amongst these are South Africa’s National Oil Company, PetroSA, and Sasol who have signed a co-operation agreement, their first in 10 years, to explore a block in the country’s offshore area Block 3A/4A, which is located within the Orange Basin, along the western margin of South Africa.

Large and relatively under-explored, the block covers 19,066 sq km, with water depths ranging from 100 to 500 metres.

PetroSA Group CEO Nosizwe Nokwe-Macamo

A significant share of South Africa’s consumption will be met with synthetic fuels (synfuels), derived from coalto-liquid (CTL) and gas-to-liquid (GTL) processes.

In practice it can be very expensive and time consuming to mobilise a drilling rig, and difficult to gain access to land. said that, in order to deliver on its mandate of ensuring security of liquid fuels supply in the country, the company entered into strategic partnerships with different entities. In the past two years PetroSA has concluded co-operation agreements with Sinopec, Eni, PetroMoc and the Korea National Oil Corporation, among others. The partnership with Sasol on Block 3A/4A has significant strategic value to PetroSA’s West Coast exploration efforts.

PetroSA also announced suspended operations at its Mossel Bay facilities for 37 days

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South Africa

from 22 September for a planned statutory maintenance shutdown, which affected the Mossel Bay gas-to-liquids (GTL) refinery and the offshore Platform. The statutory shutdown, required every four years, is aimed at ensuring the integrity of equipment and systems.

And the Orca, PetroSA's floating production and storage facility will be docked at Port Elizabeth for up to twelve months to undergo reclassification and refurbishment upgrades. The Orca FPSO was originally a drilling rig that was converted into a floating production platform in 1997. Since 2008 the Orca has been utilised by PetroSA to produce oil from the Oribi/Oryx Oilfields, which are located in Block 9, off South Africa’s southern coast.

On its side, Sasol said at its year-end results presentation in September that in South Africa a key project to ensure sustainable synfuels operations was the development of the Impumelelo and Shondoni collieries that are part of Sasol Mining’s US$1.4bn mine replacement programme.

In terms of growing its existing asset base, Sasol’s aim is to extend the lifespan of its synfuels operations to the middle of the century.

Where low-carbon power generation is concerned, CEO David Constable said that in Mozambique the group had advanced its 140MW gas-fired power plant in Ressano Garcia. Also in Mozambique, it was commissioning a US$198mn loop line to increase the

capacity of the existing gas pipeline.

Christine Ramon, financial director of Sasol, said that part of the group’s strategy was to accelerate GTL growth. “Here we are moving forward on several fronts - in Escravos, Nigeria where our third GTL plant is close to commissioning; in Uzbekistan, where we are concluding the FEED phase; and our US GTL project in Louisiana, which will be progressing to the FEED phase later this year.”

In Africa, PwC said that apart from Mozambique

joining Egypt, Nigeria Libya, Algeria and Angola as major upstream power houses in Africa, it is unlikely that Ghana or the other East African countries will disturb the equilibrium that has existed in Africa for the last two decades.

Exploration and refining capacity in Africa will continue to increase, in contrast to what is happening in the developing world, as countries strive to have a greater security of supply and increase export earnings from the sale of refined products. ■

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Geology

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Fugro wins $26mn survey contract from Total for work off Angola FUGRO HAS BEEN awarded a large three-year survey contract recently by Total E&P Angola, with an estimated value of US$26mn, to support its development programmes offshore Angola. The contract includes the provision of offshore positioning services and accurate navigation systems for Total E&P Angola’s drilling units, vessels and structures, together with onshore and offshore survey services. This contract is a continuation of services supplied to Total E&P Angola under a similar contract since 2008.

The contract is one of the building blocks for the continued development and further investment into Fugro’s activities in Angola.

38 Oil Review Africa Issue Five 2013

Global to renew project off Madagascar GLOBAL PETROLEUM HAS filed an application to renew the large 4,500 sq km Juan de Nova Est permit in French overseas territory, north-west of Madagascar in the Mozambique channel.

Global's seismic review of the area indicates a thick stratigraphic section in deep water in both the northern and southern triangles of

the block, justifying renewal.

Under the terms of the existing permit, joint venture partner Wessex Exploration maintained operatorship and 70 per cent equity.

Global holds full legal interest in the permit through subsidiary Jupiter Petroleum Juan de Nova, which has applied for renewal as

100 per cent interest holder, with operatorship, over a five year term.

Alongside the permit renewal application, a new joint venture agreement has been signed with Wessex giving Wessex the right to apply to relevant French authorities to take legal title to 50 per cent working interest, in the event of approval.

South Africa opens geoscience complex PETROSA HAS BECOME the first company to establish what it terms a “state-of-the-art” geoscience collaboration, visualisation and technology centre in South Africa.

The US$1.45mn Ulwazi (Knowledge) Collaboration and Visualisation Centre presents seismic and geological data in detailed, 3D views of subsurface formations. All disciplines of PetroSA’s upstream asset teams use the facility to assist exploration and development of oil and gas prospects.

The Ulwazi complex will be used on a daily basis to monitor and guide drilling operations for

PetroSA’s Project Ikhwezi, an initiative to secure additional feedstock reserves from South Africa’s southern offshore gas fields to sustain the Mossel Bay Gas-To-Liquids (GTL) refinery.

Nosizwe Nokwe-Macamo, PetroSA Group CEO, said: “Collaboration between our multidisciplinary sub-surface teams in Ulwazi furthers our understanding and description of geological structures and reservoirs which lead to improved decision making in areas such as well placement, field development planning, and reserves estimates.”

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THE LARGEST AUV (Autonomous Underwater Vehicle) survey in the oil and gas industry is a core element of two contracts awarded to Fugro that also include metocean measurements and geohazard consultancy services for Eni East Africa.

The data is being acquired for the Area 4 Rovuma basin development offshore northern Mozambique.

CGG awarded West Africa shoot FRENCH SEISMIC CONTRACTOR CGG has won a contract for what it describes as a “large, high-end” seismic acquisition programme offshore West Africa.

The company said it has received a letter of award to conduct a 1484-sq km BroadSeiz wide-azimuth survey for a mystery operator. The value of the contract has not been disclosed.

CGG would not reveal the identity of the client concerned. However, the file name for the accompanying press release - "PR CGG Total Angola Ang Final" - suggests it may be the French supermajor Total.

CGG said it will mobilise its vessels Geo Coral, Geo Barents and Pacific Finder to conduct the shoot.

The survey is due to start in the middle of this month and is expected to take nine months to complete.

CGG already has a five-year contract for the 4D seismic processing and imaging of annual and biennial monitor surveys planned to take place offshore Angola. More than 6,000 sq km of seismic data from five of Total’s deep offshore group of fields in Block 17, which is operated by Total in partnership with Statoil, BP and Esso, are expected to be processed over the contract’s duration.

The challenging AUV survey is the largest ever commissioned and one of the first in this new and remote frontier area off the coast of East Africa.

Fugro is providing hull-mounted reconnaissance and AUV detailed data from the development area.

The data will aid the design of subsea facilities.

Covering approximately 1,440 sq km, the survey area stretches from the nearshore to deepwater (depths greater than 2,700 metres. The work is being carried out using one of Fugro’s newest survey vessels, the state-of-the-art MV Fugro Equator, which is equipped with hull-mounted multibeam echosounder, sub-bottom profiler, piston gravity corer and piezocone penetration system, in addition to the Echo Surveyor III AUV. Meteorological and oceanographic measurements are collected using mooring buoys located in water depths ranging from 20 to 1,800 metres. To assist in the routing of the 60-km export pipeline, Fugro completed a regional and local geohazard assessment, including data processing and reporting, from its offices in Europe and Asia.

EMGS wins West Africa job NORWEGIAN ELECTROMAGNETIC SURVEY contractor EMGS has won a letter of an intent for a contract worth a minimum of US$8mn for work off West Africa.

The Oslo-listed player will deploy its vessel EM Leader on the 3D data acquisition project, though it did not disclose the client.

Chief executive Roar Bekker said the company expects the vessel to remain in the region for a longer period “based on demand from both new and existing customers.

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Geology

Fugro performs AUV survey

Gas

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Tanzania LNG decision day for Statoil STATOIL IS FACING a key decision this month to determine the technical and commercial feasibility of a planned liquefied natural gas ”mega-project” in Tanzania as it prepares to launch a further drilling campaign this autumn on its deep-water block.

Eni strikes gas again offshore Mozambique ENI CONTINUES ITS string of successful wells in offshore Mozambique Area 4 with a gas discovery at the Agulha exploration well. Work is under way to finalise the assessment and to plan an appraisal strategy.

Eni’s preliminary estimates are that the structure could hold five to seven tcf of gas, and three additional wells could be drilled in 2014.

The well is the 10th drilled in Area 4 and went to TD of 6,203 metres in 2,492 metres water depth about 80 km off Cabo Delgado.

Eni is the operator of Area 4 with a 50 per cent indirect interest owned through Eni East Africa, which holds 70 per cent of Area 4.

"The discovery opens a new exploration area in the southern part of Area 4, where Eni plans to drill three new wells in 2014," the company said.

Eni, which has already agreed to jointly develop Area 4 with Anadarko's neighbouring Area 1 field, will decide on liquefied natural gas projects in 2014 with first cargoes due in 2018.

Mozambique is now a key prospect for the export of liquefied natural gas because of the size of recent discoveries, its location en route to Asia and its appeal to buyers trying to diversify away from big suppliers Qatar and Australia.

40 Oil Review Africa Issue Five 2013

BP finds gas in Egypt BP EGYPT HAS made a "significant gas discovery" while drilling in deep waters in the eastern Nile Delta. The company announced this discovery in its Salamat well while drilling in a water depth of 640 metres in the eastern Nile Delta.

The deepwater exploration well which is the deepest well in Nile Delta, was drilled using the 6th generation semi-submersible rig “Maersk Discoverer” at water depth of 649 metres reaching a total depth of around 7000 metres.

"With a hydrocarbon column in excess of 180 m, the discovery increases our confidence ... in the East Nile Delta," Mike Daly, executive vice president of exploration for BP, said.

“Salamat discovery is a great outcome for our first well in this core exploration programme in the East Nile Delta. It shows our commitment to meeting Egypt’s energy needs by exploring the deep potential offshore the Nile Delta” said Hesham Mekawi, BP Egypt regional president.

Semi-submersible rig “Maersk Discoverer”

Mekawi added that they are currently evaluating the standalone and tie-back to the nearby Temsah infrastructure development.

RWE Dea launches gas production in Egypt RWE DEA EGYPT has produced first gas from the Disouq concession in the Egyptian Nile Delta.

The seven-field development is expected to produce a total of approximately 11.4 bcm of gas.

RWE Dea chief operating officer Dirk Warzecha said that while the German explorer had been producing oil in the Gulf of Suez for almost 40 years, Disouq was the company’s first operated gas asset in Egypt.

Gas produced from the North West Khilala (NWK) field is being collected in a temporary processing facility operated by Suez Oil Company, where it is separated into dry gas and condensate before being fed into the Egyptian gas supply grid.

By mid-2014, four of the fields will be in production and the concession will have its own central processing facility, RWE Dea said.

A peak production level of around 4 to 4.5 mcmd is expected to be achieved in mid-2014 when additionally a central treatment plant will start producing.

During the initial project phase, four of a total of seven gas fields will be brought into production by July 2014. The gas produced from the North West Khilala (NWK) field will initially be collected in a temporary processing facility, where it will be separated into dry gas and condensate. From the facility operated by Suez Oil Company (SUCO), the gas will be fed into the Egyptian gas supply grid via the state-owned GASCO pipeline system.

“We’re excited to be able to start production in this RWE Dea growth project,” said Dirk Warzecha, chief operating officer of RWE Dea AG.

BG hits more gas off Tanzania BG GROUP HAS hit more gas at a discovery off Tanzania as it readies another appraisal well and drill stem test.

The UK gas giant struck 20 metres of net pay at the Pweza-2 appraisal well on Block 4 just two kilometres from the Pweza discovery well.

Block partner Ophir Energy, which holds a 40 per cent stake with BG on 60 per cent, said the pay zone was of excellent reservoir quality and pressure communication with Pweza-1 was confirmed.

The find has firmed up the resource estimate at Pweza which stands at 1.7 tcf of gross recoverable resources.

The Deepsea Metro 1 drillship is now to move onto the Pweza-3 appraisal well while a drill stem test is also planned on the discovery.

Deepsea Metro drillship.

“These are to confirm reservoir deliverability from the cluster of Block 4 discoveries that will provide a second hub for the LNG development,” Ophir said.

“These activities are expected to be completed in early October.” www.oilreviewafrica.com

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E&P

Rig secured for West African 2014 multi-well campaign OPHIR HAS AGREED heads of terms for a deepwater drillship for its operated multi-well West African drilling programme in 2014. A total of six firm plus additional contingent slots have been agreed. The programme is scheduled to commence in Gabon in early February 2014 with drilling of the circa one billion barrel pre-salt Padouck Deep prospect on the Ntsina Block.

The second well is expected to target the Affanga Deep prospect on the Gnondo Block with the third well likely to be the pre-salt Okala prospect on the Mbeli Block.

Jubilee crude oil production hits 80mn bbls TULLOW GHANA LTD, lead operators of Ghana’s Jubilee Oilfields, has announced that the total production of crude oil in the West African country since it began operations in the last quarter of 2010 stood at 80mn barrels.

Operations Manager Bob Gettka, who was visiting the Western Corridor Gas Infrastructure Project, said Tullow earned about US$7bn in revenue from its operations on which it paid corporate tax to the government of Ghana.

Meanwhile, the Ghanaian government said it intends to save US$1.5mn a day when Ghana starts producing electric power from its gas processing plant next year.

Benjamin Asante, Director of Operations of the Ghana Gas Company (GGC), said substituting crude oil with gas in energy production was much cheaper since 120mn scfd of lean gas was required to produce 500 MW of electricity.

He said the oil wells at the Jubilee Oilfield would produce 140mn scf of raw gas per day initially and later increase this to 700mn scfd in three years.

Oryx makes Elephant discovery CANADIAN EXPLORER ORYX Petroleum believes it has a commercial discovery on its hands after striking gas and oil pay with a probe drilled at its Elephant prospect off Congo-Brazzaville.

The E-1 wildcat drilled at the prospect, formerly named Xiang, encountered gross pay zones of 102 metres and 46 metres for natural gas Jasper Explorer. and oil, respectively, across two intervals in the company’s Haute Mer A licence.

The well was drilled by drillship Jasper Explorer to a total depth of nearly 2,500 metres in a water depth of 550 metres about 80 km offshore.

It was targeting a deeper Tertiary play similar to that being tapped in fields adjacent to the licence, such as Total’s producing Moho Bilondo field and Chevron-operated Block 14 in Angola.

Henry Legarre, Oryx Petroleum's chief operating officer, stated: "We are very pleased with the Elephant discovery as it represents an important milestone in the building of our West African business.

Overall the results are consistent with expectations. Reservoir quality, crude quality and viscosity appear to be better than originally anticipated while the areal extent of the reservoir appears to be slightly smaller than expected. We look forward to working with our partners to test and potentially appraise the Elephant discovery. Although subject to testing, the discovery gives us confidence that there is further upside potential and opportunity to expand the prospect inventory in the license area."

42 Oil Review Africa Issue Five 2013

Total scores another pre-salt ‘win’ in Gabon TOTAL HAS MADE a pre-salt gas discovery in the deep-waters off Gabon, following on pre-salt oil finds earlier this year, which could galvanise investment in the country’s pre-salt potential, but only if we see more oil and less gas.

In mid-August, Total (TOT) announced an accumulation of gas condensate in a pre-salt layer of the ocean bed, some 100 km off the coast of Gabon.

The Diaman-1B successfully confirms the existence of a working petroleum system and is the first discovery drilled in the deep-water portion of the pre-salt play. The Diaman-1B well was drilled to a total depth of 5,4864 metres in approximately 1,524 metres of water. The find is about 97 km from the nearest pre-salt discovery made earlier this year by Total.

For now, there are no details as to the scale of the discovery, as Total is still analysing the data.

Total Gabon is the operator of the license, with a 42.5 per cent working interest. Marathon Oil holds a 21.25 per cent non-operated working interest, while Cobalt International Energy has a 21.25 per cent stake and the government of Gabon retains 15 per cent.

Earlier this year, Total made oil discoveries in pre-salt layers off the coast of Gabon and Côte d’Ivoire.

Spurring optimism over Gabon is the pre-salt potential of Angola, which is analogous to pre-salt darling, Brazil.

But this second find for Total brings to light the gas potential, rather than the already snowballing oil potential, and while the excitement is still there, the hope for another oil find, rather than a gas find, dulls the fervour a bit.

Indeed, shares in Marathon and Cobalt both fell on the news of the gas discovery. It’s not a huge find, and it’s not oil.

It’s an expensive drilling endeavor that will be more challenging economically and commercially than oil extraction. So far this year, Total has reportedly spent US$922mn on development in Gabon, which represents a 20 per cent increase over expenditures last year.

Gabon, however, is confident that gas will prove another boom for its economy, and it’s already preparing for another licensing round later this year for new oil and gas blocks.

Namibia study oils Chariot’s wheels CHARIOT OIL & GAS has been given a boost for an upcoming exploration campaign in its Central Area blocks off Namibia with a bullish assessment of the resource potential for the frontier play.

The explorer’s main drilling target, dubbed Prospect B, is now estimated to hold 469mn barrels of unrisked gross mean prospective oil resources, according to the independent audit by Netherland Sewell & Associates.

It also assigns mean resource estimates ranging from 213mn to nearly 1.5bn barrels to a number of other Upper Cretaceous prospects and leads identified by earlier 3D and 2D seismic data.

Chariot intends to focus its exploration efforts on a lower-risk shallower petroleum system in Upper Cretaceous turbidite reservoirs in the blocks off the south-west African state, which it operates with a 90 per cent stake with partner AziNam on 10 per cent.

The company has now launched a farm-out process to enlist a partner for exploration of the emerging province.

Chief executive Larry Bottomley said the findings of the resource audit showed “the giant scale of the opportunity” that exists within its Namibia acreage.

“Although Namibia remains a frontier and high-risk province, all the play elements of source, reservoir and seal have now been demonstrated and success in our exploration campaign would deliver transformational growth,” he added. www.oilreviewafrica.com

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E&P

Tullow makes new discovery in Kenya THE FIND IS the fourth consecutive wildcat discovery, through exploratory drilling, since 2012. It was made at the Ekales-1 wildcat, located in Block 13T in Northern Kenya. Tullow operates the Ekales-1 well, with Africa Oil taking a 50 per cent interest.

The well will now be tested to confirm productivity but reservoir volumes are expected to be over 50mn barrels gross recoverable.

The company also announced its Agete-1 well in block 13T had commenced drilling.

Angus McCoss, exploration director with Tullow Oil said: “This success at the Ekales-1 wildcat is further evidence of the exceptional oil potential of our East African Rift Basin acreage. Having opened the first basin with the Ngamia-1 well last year, we are now increasing the pace of exploration in Kenya aiming for 12 wells over the next 12 months.”

ONGC set to bid for Tanzania blocks INDIAN STATE PLAYER ONGC is likely to bid in Tanzania’s eight-block round which opens this month, according to the country’s commerce ministry.

The explorer’s overseas arm ONGC Videsh is set to join the running for seven offshore blocks and one onshore block with bidding due to start on 25 October.

India’s minister of state for commerce Daggubati Purandeswari and her Tanzanian counterpart Abdallah Kigoda discussed the round during bilateral talks in Dar-es-Salaam.

"Both the ministers agreed to double the volume of bilateral trade in the next two years and to reduce the trade imbalance, which is currently in favour of India," the Indian commerce ministry said.

2nd Jaya PSV for East Africa JAYA HOLDINGS HAS won a two-year contract valued at more than US$20mn for its new DP-2 platform supply vessel Jaya Vigilant to operate offshore Mozambique.

The vessel, originally designed as a large PSV, is being upgraded to accommodate additional equipment prior to delivery.

The work scope includes ROV support, survey work, and core sampling in water depths of up to 2,000 metres. This will require a 50-tonne subsea-rated deepwater crane and a mezzanine deck for the ROV spread, along with communications and survey pole equipment, and enhanced passenger facilities.

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China wins US$2bn Uganda oil deal CHINA’S STATE-OWNED China National Offshore Oil Corporation (CNOOC) has secured a US$2bn deal to develop a petroleum field in Uganda and help propel the east African nation into the club of oilproducing countries. The Kingfisher field is estimated to hold 635mn barrels of oil, of which 196mn are recoverable., and CNOOC will develop this over a period of four years "This is a major breakthrough as a country," Uganda's junior energy minister Peter Lokeris said confirming that a deal had been reached in September with CNOOC. "It is a milestone towards making us self-sustaining as far as oil and gas production is concerned," he added.

"The contractor, among other responsibilities, will be responsible for developing the Kingfisher oil field which should become operational in the next four years from now," the minister added.

Uganda has oil reserves estimated at 3.5bn barrels but the path to production has been a bumpy one since deposits were discovered in 2006 near its border with the Democratic Republic of Congo.

Such reserves have the potential to radically alter Uganda's economy and could eventually as much as double the national income.

Lokeris said he expected the initial output of the new Chinese-run field to be modest. "We expect to produce about 40,000 bopd once the Kingfisher well is fully developed and operational," he said.

FAR completes JV negotiations for Block L9 AFRICA-FOCUSED FAR Ltd has completed negotiations on joint venture agreements with Ophir Energy plc on highly prospective offshore Kenya exploration permit Block L9.

Block L9 is a large permit in the heart of the Lamu basin. A series of 2D and 3D seismic surveys have identified numerous oil and gas prospects and leads. FAR has assessed several leads each with the potential to contain prospective resource volumes in excess of 300mn barrels of oil (unrisked best estimate, 100 per cent basis).

FAR has already received a considerable number of unsolicited expressions of interest in Block L9 and will immediately embark on a process to farm out a portion of its 30 per cent participating interest.

Following government approval of the Block L9 joint venture agreements, FAR will pay for its participating interest of past costs (approximately US$11mn) principally relating to the two large 3D seismic surveys acquired on the permit. FAR expects to recoup a significant portion of these past costs through farming down its participating interest.

Managing director, Cathy Norman said, “The successful execution of these Joint Venture agreements is a further important milestone in FAR unlocking the significant value of its excellent acreage position in the fast emerging Kenyan offshore arena. Ophir provides extensive operational expertise to our joint venture and we hope to be drilling our first exploration well on this block in late 2014. Success on this well would likely have a profound impact on the value of FAR.” Block L9 was originally awarded in May 2011 with Dominion Petroleum Kenya Ltd (a wholly owned subsidiary of Ophir) the nominated operator on the permit. Since then FAR and Ophir have been negotiating the terms of joint venture arrangements for FAR to obtain a 30 per cent participating interest.

Block L9 contains well developed large carbonate Miocene reef structures that are perceived to be oil prone. There are turbidite sands at several levels over most of the permit with potential for both structural and stratigraphic plays. The eastern part of the block is on trend with the Mbawa-1 gas discovery where several large structural leads have been identified. Good quality Tertiary and Cretaceous marine clastic reservoirs are likely to be present and sealing shales are widespread. The Block L9 Joint Venture anticipates drilling its first exploration well in late 2014.

www.oilreviewafrica.com

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E&P

Libya's NOC interested in Marathon Oil stake in Waha Oil LIBYA’S OIL MINISTER Abdelbari Arusi has revealed that National Oil Corporation (NOC) is considering buying US oil major Marathon Oil's stake in Waha Oil Company.

According to a Reuters news report, the Waha Oil Company in Libya has the capacity to produce 350,000 bpd and manufactures Libya's main light sweet crude grade. The company operates four oil fields, the largest being the Waha oil field. Waha Oil Company manages oil for several companies through its production lines running from the Sirte Basin to the Es-Sider terminal. Hess Corp and ConocoPhillips along with the NOC, are the other two partners in Waha.

Arusi said, "Regarding Marathon, yes, we're interested to buy the stake. Libya would discuss a potential deal with Marathon, though other firms are also interested.”

Separately, Arusi also revealed that Libya was reviewing terms for existing investors and on how to ease them into the next round of licensing for exploration and production, which will be announced in the first half of 2014.

46 Oil Review Africa Issue Five 2013

Sinopec clinches Egyptian oil deal CHINA PETROCHEMICAL CORP, or Sinopec Group, has agreed to pay US$3.1bn for a 33 per cent stake in Apache Corp's Egyptian oil and natural gas business, its biggest purchase in the Middle East and a sign of China's increasing overseas energy investment.

The deal is the first stage of a partnership between China's largest refiner and the Texas-based exploration and production company. The two companies aim to pursue joint upstream oil and gas projects.

The operations that are being acquired, located in the Western Desert and away from the centres of political unrest in Egypt, will add daily output of about 130,000 barrels of oil for Sinopec Group, the company said.

The deal is expected to close in the fourth quarter, and it will be Sinopec's biggest such transaction since the 2010 purchase of Syncrude Canada Ltd. "Their (Sinopec's) technical expertise complements our 20 years of experience operating in Egypt and creates an alliance that will continue to explore and deliver the tremendous hydrocarbon resources in the Western Desert," Steven Farris, chairman and CEO of Apache, said.

Wei Fujun, a spokesman at Sinopec International Petroleum Exploration & Production Corp, the unit making the purchase, said that Sinopec is aware of the political uncertainties in Egypt and is focused on longterm development in the region. Wei termed the price of US$3.1bn "very reasonable".

The deal is viewed by some analysts as a sign of China's increasing investment in Africa as it secures energy resources.

Chinese companies have completed 83 overseas oil and gas purchases worth US$100.7bn in the past five years. CNOOC’s US$15.1bn acquisition of Canada-based Nexen Inc early this year was China's largest overseas acquisition.

www.oilreviewafrica.com

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The Baker Hughes Rig Count tracks industry-wide rigs engaged in drilling and related operations, which include drilling, logging, cementing, coring, well testing, waiting on weather, running casing and blowout preventer (BOP) testing.

SEPTEMBER 2013 - LAND & OFFSHORE SEPTEMBER 13 Country Land & Offshore ALGERIA 46 ANGOLA 13 CAMEROON 3 CHAD 3 CONGO 3 EQUATORIAL GUINEA 0 GABON 3 GHANA 1 COTE D'IVOIRE 0 KENYA 10 LIBERIA 0 LIBYA 12 MOZAMBIQUE 2 NIGERIA 15 TANZANIA 1 TUNISIA 2 UGANDA 2 D R CONGO 1 NAMIBIA 1 SOUTH AFRICA 0 MAURITANIA 1 ETHIOPIA 0

AUGUST 13

VARIANCE

SEPTEMBER 12

Land & Offshore 49 12 3 2 3 1 9 0 0 9 0 15 1 14 1 1 2 1 1 0 1 0

From Last Month -3 1 0 1 0 -1 -6 1 0 1 0 -3 1 1 0 1 0 0 0 0 0 0

Land & Offshore 42 5 0 2 2 1 5 1 2 2 1 13 1 19 1 5 3 1 1 0 0 0

AUGUST 12 Land & Offshore 46 9 0 2 2 1 7 2 2 2 1 11 1 18 2 3 1 1 0 0 0 0

VARIANCE From Last Month -4 -4 0 0 0 0 -2 -1 0 0 0 2 0 1 -1 2 2 0 1 0 0 0

Source: Baker Hughes

Canadian Natural Resources farms out Block 11B/12B offshore South Africa CANADIAN NATURAL REOURCES Ltd (CNR) and Total E&P South Africa BV will jointly explore Block 11B/12B offshore South Africa. The farm-out agreement will provide Total with a 50 per cent working interest in the block and the right to operatorship, with CNR receiving an undisclosed upfront cash payment, a recovery of 50 per cent of past incurred costs and a carry in the first exploration well drilled, up to a maximum of US$150mn.

CNR has performed seismic studies on Block 11B/12B and now the newly formed consortium will work towards finalising the location of the initial exploration well. Drilling is slated for 2014.

The Calgary-based energy firm chose Total after a "lengthy and thorough process" because of its expertise in deep water exploration.

"The exploration potential in this offshore area of South Africa is exciting,” commented Steve Laut, president of Canadian Natural, in a press release. “We are pleased to have the opportunity to work together with Total, a world class partner.

The completion of this joint venture demonstrates the opportunities provided to the company through its international

48 Oil Review Africa Issue Five 2013

portfolio which contributes to our vast and diversified asset base. Working together with Total and the Government of South Africa, we are in a positive position to maximise shareholder value in this exciting prospect."

Situated in the Outeniqua Basin, Block 11B/12B lies 109 miles off the southern coast of South Africa and spans 4.6mn acres. Water depths range from 200 to almost 1,800 metres. www.oilreviewafrica.com

S12 ORA 5 2013 Technology A_Layout 1 22/10/2013 16:54 Page 49

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S12 ORA 5 2013 Technology A_Layout 1 22/10/2013 16:54 Page 50

Galloping forward

Tanzania to start power exports in 2015

UPSTREAM DEVELOPERS OF Kudu gas field off the coast of southern Namibia are hoping to finalise a sales agreement with energy utility Nampower by mid-next year, paving the way for exploitation of the massive fields and construction of an 800MW gas-to-power plant.

The Namibia Power Corporation is the sole buyer of gas from the Kudu field, which is estimated to contain 1.3 tcf of proven natural gas reserves.

And the good news for Namibia does not end there: recent exploration and additional data analysis is said to suggest that reserves could reach three tcf.

Exploitation of Kudu, which is located in the Orange Sub-Basin, has been on the cards since gas was discovered there in 1974.

One of the major reasons for Kudu failing to take off has been the absence of a gas sales off-taker and the failure for interested parties to reach an agreement on whether the pricing of the gas should be denominated in local currency or US dollar.

The Namibian government recently directed Nampower to fasttrack the construction of a US$1.2bn power plant.

As such, Nampower is the sole beneficiary of the gas from the Kudu field and an agreement on pricing, if reached before or in 2014, could pave the way for the exploitation of the resource and the construction of the Kudu Power Plant.

Plans are for the power station to be on-line in 2018.

“All the gas pumped from the Kudu fields will be committed to the Nampower plant and nothing else,” Namcor MD Obeth Kandjoze said last week.

“The pricing of the gas will be denominated in US dollars and this is no longer a point of negotiation.”

TANZANIA, WHICH HAS made big natural gas discoveries, plans to start power exports to its energy-starved east African neighbours in 2015 after the completion of a gas pipeline.

East Africa's second-biggest economy said the pipeline, funded by a US$1.2bn Chinese loan, would be completed by December 2014 enabling the country to double its power generation capacity to 3,000MW. Energy and minerals minister Sospeter Muhongo said Tanzania, which currently imports around 14MW of electricity from its neighbours and suffers from chronic energy shortages, was poised to become a net power exporter within the next two years.

"We are on course to start power exports in 2015 because of the surplus electricity that we will be producing after the completion of the ongoing pipeline construction," Muhongo said after recently inspecting construction of the 532 km pipeline on the outskirts of Dar es Salaam.

He said Kenya had made enquiries about importing some 1,000MW of electricity from Tanzania.

Tanzania has 43.1 tcf of recoverable natural gas reserves and anticipates that will rise fivefold within the next two years if new finds prove productive.

In July the country also revised its coal reserves to 5bn tonnes from about 1.5bn tonnes, and said it plans to use coal and gas for power generation.

Muhongo said Chinese firms had recently shown interest in Tanzania's oil and gas sector and were expected to bid for blocks in its October oil and gas exploration bid round.

Tanzania has so far licensed 16 international energy companies to search for oil and gas. British gas firm BG Group , Norway's Statoil, Brazil's Petrobras, Royal Dutch Shell and Exxon Mobil Corp are among companies already operating in Tanzania.

Ethiopia to be regional power exporter ETHIOPIA IS SHAPING up to be the great regional power supplier. It currently exports electric power to Sudan and Djibouti, and plans to supply five other neighbours, including Egypt, Kenya, Uganda, Somalia and South Sudan, once it completes the 5,250MW Grand Ethiopian Renaissance Dam, currently under construction.

In July 2013 the country signed a second power transmission agreement with Djibouti. The terms of the document allows Djibouti to import between 35 and 70MW from Ethiopia. The transmission interconnection is billed to cost US$2bn.

The transmission line, which covers areas from Semera, in Ethiopia's Afar regional state, to Jaba in Djibouti, will be rated at 230 kV, the same capacity as the first transmission line connecting the two countries. The African Development Bank financed 80 per cent of the first power transmission line, which cost US$1.5bn to construct, with the balance coming from the two countries. The new transmission line will meet 60 per cent of Djibouti's power demand, with Ethiopia earning up to US$1.5mn a month from the exchange.

Ethiopia is in a race with itself to be the continent's largest hydropower generator. Over the next 10 years it aims to invest US$12bn in power projects that will generate 20,000MW, enabling energy sufficiency and power export to neighbouring countries.

50 Oil Review Africa Issue Five 2013

Aggreko plant expanded to supply power to Namibia and Mozambique AGGREKO, IN CONJUNCTION with its project partners, has celebrated the expansion of its gas-fired power plant at Gigawatt Park in Ressano Garcia, Mozambique. The extension to the facility was officially inaugurated by the Mozambique minister of energy, the Honourable Salvador Namburete, during a ceremony held at the project site. The expansion adds an additional 122MW of capacity to the Ressano Garcia facility, bringing the total generation output from the plant to 232MW. The Aggreko power plant began operating in July 2012 in what was the realisation of a truly ground-breaking initiative to build the world’s first interim cross-border Independent Power Producer (IPP) project. Power generated on site was supplied directly into the Southern African Power Pool (SAPP) with the first off-takers from the project being Electricidade de Moçambique (EDM), the Mozambique power utility and Eskom, the South African power utility.

Following the success of the first stage of Ressano Garcia, Aggreko announced in March 2013 that it had signed agreements with both EDM and NamPower, the Namibian power utility to supply an additional 122MW from the project. Following this announcement work began immediately to more than double the generating capacity of the plant. As Aggreko designed and built the plant infrastructure to allow for modular increases in capacity, adding the additional power generation was achieved in just 12 weeks.

By utilising the exceptional regional transmission infrastructure of the SAPP, Aggreko will now supply power generated in Mozambique to three national utilities, including to Namibia located more than 1,500 km away.

Highlighting the mutual co-operation between the utilities to make this possible, both EDM and Eskom will play a key role in transmitting this power to Namibia. EDM will transmit the power over its network to the South African border where Eskom on behalf of NamPower will handle the wheeling of the power across the South African grid network to Namibia.

www.oilreviewafrica.com

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Exalo Drilling S.A. is one of the largest providers of drilling and oilfield services in Central and Eastern Europe(CEE).

The strategic goal of the company is to offer top quality services and maintain the leading position on the onshore drilling market.

Exalo Drilling S.A. continues the rich tradition of Polish exploration as it arose from five upstream companies of PGNiG Group: PNiG Krakow S.A.,PNiG Jaslo S.A., PNiG NAFTA S.A., PN Diament Sp. z o.o., and ZRG Krosno Sp. z o.o., which have unique experience in running drilling and service operations. The companies greatly contributed to the development of extraction of petroleum, gas and other natural resources in the territory of Poland and many countries all over the world .

The joint potential of five companies means a strong team of highly competent and experienced specialists as well as comprehensive technological base that allow to meet customer expectations and fulfill the growing demand of international markets.

www.exalo.pl marketing@exalo.pl

Exalo Drilling S.A. Experience Synergy Quality

Technology

S12 ORA 5 2013 Technology A_Layout 1 22/10/2013 16:54 Page 52

West Africa is proving to be one of the biggest growth areas in the world today for the oil and gas industry. Strong oil prices combined with rising demand and major offshore discoveries have resulted in the creation of an exciting and dynamic region, and Wood Group Kenny (WGK), part of the international energy services company Wood Group, has already worked on a number of prestigious West African projects prior to establishing a permanent presence there.

Training - the route to developing global expertise

with a local focus A

VARIETY OF factors have characterised WGK’s experience of working in this region to date. Water depths which exceed 2000 metres in the deepest areas, have resulted in field developments which are technically challenging. In such a vast continent, and with the relative infancy of the deepwater industry in the region, it is perhaps inevitable that there are some logistical hurdles when it comes to transporting equipment or dealing with unplanned events. As is the case across the industry, environmental conditions and the elements create their own challenges, but on the people front, training has also been a significant and important part of WGK’s African experience.

As international companies have become increasingly involved with the development of the industry in West Africa, the authorities have been keen to ensure that local people benefit from the opportunities that are created, and this is something which WGK supports. In Nigeria, local content laws ensure that the majority of engineering is carried out in country, and 70-75 per cent of staff must be Nigerian. Because of the relatively recent rise in the number of deep water developments in the region the existing pool of required skills is currently insufficient to meet demand, making training a central part of achieving that goal.

At the same time, the oil industry is facing a global skills shortage and a “demographic cliff” which is particularly acute in the subsea sector. In recent years it has become very common for subsea tie-backs to be installed around existing platforms and infrastructure. As a result, major operating companies have experienced a considerable rise in the percentage of their portfolio that involves subsea development, thereby creating strong demand and competition when it comes to recruitment of experienced engineers.

It therefore makes sense from all perspectives, for international companies working in the region to invest in and grow local talent – it has benefits not only for the local population, but for the industry as a whole.

WGK is implementing an approach to training in West Africa that has successfully been applied in other countries, such as Indonesia, India, Brazil and Malaysia, and to target training at different stages of people’s careers. For example, dynamic riser design is a highly specialised area of technology, particularly for the deepwater developments that are prevalent offshore West Africa, and it is an area where skills are in short supply. Consequently for an

52 Oil Review Africa Issue Five 2013

Ariel fly by of offshore drilling rig.

It makes sense, from all perspectives, for international companies working in the region to invest in and grow local talent. upcoming project in Nigeria, WGK will be training experienced local engineers to provide additional specific riser-related skills.

“Sandwich courses” are a well-established route to helping students acquire the practical experience that is so important to the workplace, and we have offered placements to African students as part of their university degrees. Our unique online subsea training academy forms part of the initial training programme for all graduate engineering recruits around the globe, including those in West Africa, which may be followed by a placement in a WGK overseas office before they return to their respective home countries to work.

Adapting training programmes to specific needs WGK is adapting its training programmes to meet the specific needs in the region, including working with local educational establishments to develop specialised oilfield courses. In addition, there are on-going efforts with Scottish Development International to establish links with Scottish training institutions and help transfer skills from the now mature UKCS to West Africa.

Operational safety is an especially important priority throughout the industry and existing standards that are achieved may vary around the globe. Where safety standards are high, it is important to transfer the safety culture that exists as a result of decades of experience, to emerging countries via lessons learned and research. Safety remains an area in which the industry strives for continued improvement through the framework of initiatives such as the UK based partnership Step Change in Safety, which provides a focus for cooperation, collaboration and sharing of best practice. In developing regions like Africa, the opportunity exists to share knowledge and embed best practice through training.

Safety - top priority The company feels strongly that it is bringing its international technical expertise into the region and so will also bring with it the benefits of the years of experience gained in other parts of the world with respect to safety. Indeed “Safety and Assurance” is the most important of the seven core values that form the cornerstone of how Wood Group businesses conduct themselves and deal with others. An integral part of this is the fostering of a culture of empowerment and shared responsibility for safety throughout the workforce. In other words, every employee needs to be able to recognise an unsafe situation and report it; they need to stop and say “I’m not doing that because it isn’t safe”.

Whilst that sounds straightforward in practice, the more difficult thing is often engendering the

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Technology

“Safety and Assurance” is the most important of the seven core values. safety amongst a diverse workforce, and provision of safety specialists to engender a safety culture within projects is an important step to achieving this.

By working closely with local partners in West Africa to close the skills gap and increase technical expertise within the region, international companies can build long lasting relationships and contribute to the development of an engineering hub which applies global expertise to provide world class local solutions. ■

Aidan O’Connor, Nigeria in-country manager, Wood Group Kenny and Philip Reina, Business Development African Region, Wood Group Kenny

Because of the relatively recent rise in the number of deep water developments in the region, the existing pool of required skills is currently insufficient to meet demand, making training a central part of achieving that goal.

confidence to speak up. It is a highly complex task that requires constant positive reinforcement.

Ingrained cultural attitudes and behaviours may need to be overcome in order to successfully build an effective safety culture and a recently published paper proposed that efforts to improve safety performance within the industry will be enhanced if the prevailing national culture is 1 assessed and a location-specific plan developed .

For example, within some cultures people may feel especially uncomfortable when it comes to questioning their seniors or those in authority. As an industry we need to reinforce that any individual has the right to question or stop a task if he or she deems an activity or operation may be unsafe, regardless of who has ordered the work.

We need to embed an environment of mutual trust and shared perceptions of the importance of

Ref: 1. The Impacts of National Culture on Safety Culture in the Global Oil and Gas Industry Steve Merritt, Chevron Corporation, 2012, SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production http://www.onepetro.org/mslib/app/Preview.d o?paperNumber=SPE-156638-MS

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54 Oil Review Africa Issue Five 2013

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S12 ORA 5 2013 Technology A_Layout 1 22/10/2013 16:54 Page 55

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S13 ORA 5 2013 Technology B_Layout 1 23/10/2013 16:14 Page 56

Technology

On board an FPSO, one of the areas of high concern for an owner is the selection of coatings for the water ballast tanks.*

Ensuring asset integrity

on board an FPSO Coatings provide a critical path to reducing corrosion on offshore structures.

M

AINTAINING OFFSHORE ASSETS, whether FPSO or other floating structures, is not a straightforward matter and does not have a ‘one size fits all’ approach. The reality is that maintenance begins the day the first paint is applied at new construction. Selection of a paint that is not appropriate for the service environment and asset lifetime is where the first mistakes are made.

The steel inside the ballast tanks is very sensitive to corrosion because of the combination of chloride ions, water and air.

In this respect International Paint find that the industry trend for FPSOs is to select coatings which are able to help maintain asset integrity for a greater time period, typically 20 years. On board an FPSO, one of the areas of high concern for an owner is the selection of coatings for the water ballast tanks. These tanks play a crucial role in stabilising the FPSO as the crude oil is offloaded. Typically this happens every 10 days. Standard water ballast tank coatings, as used on other marine vessels, are not always applicable for FPSOs. The action of ballasting means highly corrosive sea water is moved around inside the ballast tanks. As a result the steel inside these tanks is very sensitive to corrosion because of the combination of chloride ions, water and air. This is made even worse by the warm and humid air within the tanks. In hot climates this becomes even worse and for this reason owners want to ensure that the coating used in the ballast tank is a premium coating. International Paint’s Intershield 300 is a pure epoxy paint with greater than nine per cent aluminum content and a proven 15 year

56 Oil Review Africa Issue Five 2013

performance. The high aluminum content in the dried film of this coating is one of its key properties to ensure excellent anticorrosive properties required for long lifetimes. This is in addition to its careful formulation to show good film thickness retention around edges. This is often one of the areas where coatings break down first. Overall, International Paint experience customers of both conversion and new build FPSOs requesting Intershield 300.

Maintenance procedure for long service offshore structures The correct maintenance procedure for long service offshore structures such as FPSOs begins before they even leave the construction yard. International Paint always recommend a detailed inspection survey is carried out to identify areas of the asset where the coatings applied are at risk of failing after any additional work or modifications on board the topside structures. For instance, such an inspection could identify areas that may have been affected by hot welding in close proximity. Having this documented means that the onboard maintenance teams on the FPSO have a clear idea on what areas need to be addressed first. It is important to remember FPSO and offshore assets are akin to chemical and refining plants, and so have unique micro-environments on board. The average FPSO will have many miles of piping all stacked on top of each other. Each and every area should be detailed.

Only then can you prioritise coatings maintenance and pass on the correct repair procedures.

It is more straightforward to carry out such a survey before the asset leaves the yard.

Opportunities to carry out such inspections once offshore are much harder to facilitate and bear a significant increase in cost.

Ensuring longevity of coatings on an FPSO Ensuring longevity of a coating requires large capital investment in product testing. The challenges for offshore assets led to the specific

development of ISO 20340, which details “performance requirements for protective paint systems for offshore and related structures”. This standard should always be universally adopted as a minimum during coatings selection.

The hulls of FPSOs will require inspection from Class Societies to ensure asset integrity.

Within ISO 20340 minimum test requirements are details for ageing, sea water immersion and cathodic disbondment of coatings. The latter is extremely important for FPSOs which typically rely on cathodic protection of hull structures, either with sacrificial or impressed current, in conjunction with coatings, to protect them.

One also encounters owners and operators with large fleets distributed across the world who wish to go above and beyond this standard. Oil majors such as Shell and ExxonMobil are just some who have outlined extra requirements, to which International are also qualified. Some of these include basic testing of over-applied paint for instance. This may sound simple but the reality is that control of film thickness can be hard around complex structures such as the base of modules on decks. A good coating is formulated in such a way to tolerate over-application.

International Paint spends in excess of millions of Euros on research and development each year to satisfy the needs of customers and ensure new products are fit for purpose. Internationals Paint central support labs are in continuous use, testing and approving products for the offshore industry.

With this level of investment, Inter¬national is able to develop tests in the absence of industry standards to help customers. One such example is

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Technology

S13 ORA 5 2013 Technology B_Layout 1 22/10/2013 16:59 Page 58

with International Paints high temperature under insulation product Intertherm 751CSA. Corrosion under insulation is a real problem for the oil and gas industry as layers of insulation can lead to a moist and warm environment, which is perfect for corrosion.

The insulating layer often hides this problem until it’s too late. Traditionally there was no industry standard for this scenario, and International Paint’s customers asked them to help develop a test that they could use to determine product selection for this environment. This test is now widely publicised and becoming rapidly adopted by the industry.

Key steps in application for maintenance and new building of FPSOs Application of any coating begins with the correct surface preparation on the substrate. In the case of new building FPSOs this is generally always grit blasting, which creates a surface profile on the steel and helps remove residual salts. Blasting should always be done to Sa2.5 (ISO 8501-1). To determine the salt levels owners should insist on using ISO 8502-9. However, when one is in a maintenance situation offshore, it is too costly and

not always practical to use abrasive blasting equipment. An alternative is to use ultra high pressure water jetting. This removes paint residues and exposes the original blasted surface profile.

It is also important to realize that coatings are designed with different surface preparation techniques in mind.

Environmental selections

consequences

on

As FPSOs remain stationary for most of their lives, there are not the same requirements of fuel savings to be gained by use of antifouling coatings which reduce fuel emissions. However, importantly, the hulls of FPSOs will require inspection from Class Societies to ensure asset integrity. Therefore this need to inspect means biocidal or foul release coatings are often applied on the hulls and jackets of offshore structures. Foul release fluropolymer coatings are the direction in which the industry is moving. This technology does not rely on a predetermined level of biocide in the coating. The surface energy of foul release coatings means that organisms cannot firmly adhere to them. No biocidal antifouling can protect

In hot climates sensitivity to corrosion becomes even worse - here the FPSO Kwame Nkrumah in the Jubilee oil field off Ghana.

an FPSO over a long period. International Paint recently supplied Intersleek 970 fluropolymer coating to the hull of a large conversion FPSO destined for the West Coast of Africa. Class societies know that such coatings are easy to clean and thus enable the condition of the hull to be easily documented. ■

*Toby Stein, upstream oil and gas market manager at International Paint.

HEMPADUR 35760: the ultimate solution for tank linings and coatings HEMPADUR 35760, A heavy-duty tank lining solution, 100 per cent Volume Solids product offers superb corrosion protection and excellent chemical resistance.

Developed specifically to satisfy the requirements of demanding storage operations, Hempadur 35760 is the ideal coating and lining solution for tanks storing oil, gasoline, fuel, petroleum products and a wide range of chemicals. As one of the finest two component products on the market based on the most innovative phenolic epoxy resins available, it offers the best possible resistance against chemicals. It can also be used as a filler layer with glass mats for repairing bottoms of chemical storage tanks or to coat an entire tank.

Hempadur 35760 is the product of Hempel’s years of experience and feedback from highly demanding customers in the industry. Hempel knows the extent of damage weak corrosion protection might cause to a business.

As a high-solids product that can be applied in high film thickness, Stopping trouble before it starts.

Hempadur 35760 cures to a highly durable tank lining with excellent corrosion protection and resistance to chemical exposure, making it the perfect lining solution for industrial and commercial tanks and at the same time guaranteeing the safe containment of their content with zero contamination.

To demonstrate an example system to coat the interior of a tank for fuel oil, it can be applied in two layers of 250 micron film thickness to form a tough coating that ensures excellent chemical resistance.

Example of system to coat the interior of a tank for fuel oil:

58 Oil Review Africa Issue Five 2013

Paint Type

6 High-build phenolic epoxy (solvent free)

Hempadur 35760

250 micron 6 High-build phenolic epoxy (solvent free) 250 micron

Hempadur 35760

Hempadur 35760 is a solvent-free, two-component, high-build phenolic epoxy (novolac) paint that will deliver the perfect solution, whether the job is to repair or line chemical storage tanks. It cures to a glossy and smooth finish, making it easy to clean the lining and inspect the tank for damage.

It is easy and safe to apply. It requires no special equipment for application, and as a 100 per cent solids, solvent-free epoxy, it poses no explosion or ignition risk when being applied in confined spaces.

Due to exposure to different temperatures and chemicals, commercial and industrial tanks deteriorate over time. Hempadur 35760 can be applied to refurbish tanks that are already showing signs of corrosion, saving businesses from major costs and from having to replace tanks.

Not having to replace old tanks already reduces the environmental impact from business operations. It takes this one step further as a low-VOC paint that also satisfies the EU’s environmental legislation.

Hempel sets the standard for tank linings and repair with Hempadur 35760, the ideal solution that satisfies all customer, industry and legislation demands.

www.oilreviewafrica.com

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Technology

Hardide Coatings unveils groundbreaking new technology HARDIDE COATINGS HAS developed an innovative coating to extend the life and improve the performance of drilling tools operating in extremely abrasive environments. This is the first successful high performance coating for TSP (thermally stable polycrystalline) diamonds which can withstand the higher temperatures associated with TSP brazing, extreme loads and aggressive media.

This will enable a new generation of diamond-based hardfacing materials to be deployed in extremely abrasive wear and erosive conditions such as horizontal and directional drilling, as well as fracking.

Improved tool performance will enhance the viability of more challenging or marginal oil and gas reserves.

Hardide Coatings CEO Philip Kirkham said: “Drilling activity is taking place in deeper and more demanding conditions than ever before and tools need protection from extreme abrasive wear and erosion that current hardfacing materials can no longer provide.

“Some critical drill string components need replacement after every drilling programme, so the new coating application will reduce expensive maintenance and down time costs of drilling projects. This will in turn boost the economics of smaller and more mature oil and gas fields, such as those in the North Sea.” Diamonds are notoriously difficult to attach and are prone to oxidation and graphitisation, limiting their hardfacing use to date. Previous attempts to solve these problems have been unsuccessful due to the porosity of other coatings and their weak adhesion to the diamonds. Hardide-D overcame these hurdles with its pore-free tungsten carbide based adhesive and protective coating which chemically bonds to diamond and has good wettability with brazing alloys.

The coating was developed in the company’s Oxfordshire manufacturing facility following several years of fundamental research. The production process was developed with the support of a Technology Strategy Board (TSB) ‘Smart’ grant for up to US$400,000 which was awarded in January 2013. The technology is covered by new UK and international patent applications.

Hardide Coatings has signed a mutually exclusive five-year supply agreement with hardfacing specialists Cutting & Wear Resistant Developments Lyd of Sheffield, UK, for its use in oil and gas applications.

Jotachar JF750 - the time saving solution OWNERS AND OPERATORS know that all offshore structures represent a valuable asset as both capital expenditure (CAPEX) and source of ongoing revenue.

The balance between CAPEX and return on investment is an important aspect; however, the operating expenditure (OPEX) is also a factor that strongly influences how fast one will have return on investment. By striking the right balance between investing more up-front one will most likely save on OPEX in the future.

Another factor also needs to be considered. Due to technological advances many offshore structures are reaching the end of their design life if they have not already done so. This scenario is also likely to occur in the future as a result of these developments By investing a small amount during construction in high quality coatings solutions and running a good maintenance programme, it can be argued that there will be savings in OPEX cost and downtime will be reduced to a minimum, and in some cases even saving major investment in refurbishing installations that have exceeded their design life.

Jotun has been a leading provider of high-quality coating systems for stationary and floating steel structures for almost a century, and has become a truly global supplier of high performance coating solutions to the offshore industry.

Its latest innovation is Jotachar JF750 (for more information, see Oil Review Africa Issue Four, page 60) the only mesh-free epoxy intumescent coating solution available to the market where jet fire protection is required for safety critical steel structures, divisions and vessels.

Jotachar JF750 mesh free benefits help owners, fabricators and applicators significantly reduce installation time, cut material cost and reduce risks compared to systems that require mesh reinforcement. The product also makes maintenance and repair much simpler, requiring significantly less time and cost.

Traditional mesh containing epoxy PFP

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Mesh free Jotachar JF750

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Technology

Belzona has a proven track record of success within the oil and gas industry for the protection of process vessels operating at elevated temperatures.

Cold applied vessel linings

take the heat 0

0 0 0 0 0 0 0 0 0 O FFSHORE PROCESS VESSELS operating at elevated temperatures and pressures represent one of the most arduous service environments and major challenges for the asset owners and operators. These vessels, and in particular those involved in the separation of oil/water and gas as it enters the process stream, are constantly subjected to a wide variety of aggressive conditions which can ultimately lead to severe internal corrosion.

Belzona’s successful track record dates back to 1989 and during this time considerable resources have been placed on product development for this particular sector of the industry. This has led to Belzona coatings being widely used by most of the major oil companies worldwide.

During 1994 linings resistant to temperatures of up to 120°C were introduced. In addition, these materials offer excellent resistance to explosive decompression, and have been successfully used worldwide for the protection of well test separators, production separators, knock-out drums and a variety of other types of process equipment.

Deeper wells – higher operating temperatures However, with the sinking of increasingly deeper wells leading to higher operating temperatures and pressures, vessel operators are faced with a difficult task to combat the problems associated with this kind of service environment. As a result, materials able to resist more arduous environments had to be developed.

When designing systems that are resistant to high temperature immersion, it was important to consider the reasons why conventional coatings fail. Many such materials are solvent-based, and in these instances, quite apart from other limitations, problems are experienced due to solvent retention within the film.

This retained solvent will then increase in volume as it is exposed to higher temperatures, which in turn leads to blistering. Furthermore, in some cases, exchange takes place between the retained solvent and the process fluid leading to swelling and premature failure.

Belzona high temperature vessel lining.

Offshore process vessels involved in the separation of oil/water and gas as it enters the process stream, are constantly subjected to a wide variety of aggressive conditions, which can lead to severe internal corrosion.

As a result of deeper wells, materials able to resist more arduous environments had to be developed.

A desire for more environmentally friendly systems has made the use of volatile solvent-based resin systems increasingly unacceptable.

Systems with low cross-link density are susceptible to a high degree of permeation of both water and gases leading to corrosion. This phenomenon increases dramatically as the polymer system reaches its softening point, whereby distances between the polymer molecules’ cross-link sites increase and permeation occurs more readily. Even conventional epoxy resins, which typically display good resistance to permeation at ambient temperatures, can only offer limited protection at ‘elevated’ temperatures.

Novel solution to high temperature immersion The culmination of this high temperature coating research project was the introduction of Belzona 1591 (Ceramic XHT Metal), in December of 1998, following a successful field trial programme. It was later reformulated in 2003 to ease application procedure.

The high immersion resistance of this product is attributed to a novel modification to the existing resin system. In addition, a unique binary cure system allows the rapid development of immersion resistance during post cure in service. The resulting system displays a very high glass transition temperature, which means it is more highly cross-linked at elevated operating temperatures than conventional systems.

By utilisation of a polymer matrix with a high cross-link density coupled with reinforcing fillers, which give barrier protection, the tendency for water and gas permeation can be dramatically reduced thus leading to immersion resistance at

60 Oil Review Africa Issue Five 2013

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Think Well Testing, Think Well Fluid Services

Well Fluid Services Limited was incorporated in 2001 as a wholly indigenous Oil Service Company to serve the Oil & Gas industry in Africa and beyond. Our services include: t Well Clean-up / Testing t Extended Well Testing and Early Production Facility t Sand Detection, Quantification, Removal, Onsite Analysis and Disposal t Temporary Well Hook-up t Data Quality validation t Production Operator Supply to man production platforms t Effluent Water Treatment

Tel: Mail: Web:

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Technology

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higher water temperatures. Extensive in-house testing, including more than 150 elevated temperature/pressure immersion tests using autoclaves revealed: 6 Heat distortion temperature in excess of 250°C. 6 Immersion resistance in water/hydrocarbon service up to 180°C. 6 Rapid post cure in service, eliminating the need for extensive stoving periods, and reducing the risk of permeation during the initial post cure in service.

6 Physical properties that show only moderate change across a temperature range from 0-200°C. 6 Limited reduction in adhesive strength across the same temperature range, a contributory factor to the coatings excellent high temperature immersion characteristics.

Put it to the test Following on from the excellent results obtained in-house, Belzona 1591 (Ceramic XHT Metal) was submitted for an extensive programme of field trials and external testing. Included in this programme were a series of tests carried out by a major oil and gas exploration and production company to evaluate the suitability of paint and coating systems for oil/ brine service at temperatures up to 130°C and 30 bar pressure. This test programme which involved a series of immersion periods followed by explosive decompression cycles, confirmed the data obtained in-house and the suitability of this product for high temperature immersion under these conditions. This material has now been added to this company’s TAMAP (Technically Accepted Manufaturers and Products) list and is also listed under Protective Coatings for Onshore and Offshore Facilities.

Further independent immersion testing has confirmed the suitability of this product for operation in brine service up to 180°C. Throughout the development of the product close consultation with potential end-users has been of paramount importance. This was typified by the collaboration between Belzona and a global client responsible for the manufacture of a new FPSO. Belzona was approached to offer a suitable protection system for the internal surfaces of the test separator, production separator and flare knockout drums.

As the operator had already committed to producing the vessels from carbon steel it was of paramount importance that the coating system designed for internal protection of the vessels was of the highest possible standard.

Due to the aggressive conditions likely to be encountered it was considered necessary for any coating system to be extensively tested in the actual service environment, in the region of 130°C. At the request of the field operator, Belzona carried out an extensive test programme, exposing the coating to a variety of expected process fluids at 130°C. After the initial testing had satisfied the customer of the suitability of the coating system, immersion in simulated process water, identified as the most potentially damaging of the service conditions, was continued. This lasted for a period of 12 months at an increased temperature of 150°C. Vessel inspected in January 2013, lining in excellent condition.

Vessel lining application in 2009.

Throughout the development of the product close consultation with potential end-users has been of paramount importance.

As a result of this successful test programme, Belzona 1591 (ceramic XHT metal) was selected for the protection of all internal surfaces of a variety of process vessels for this new facility. This included the main process separators, high pressure and low pressure flare knockout drums and coalescer drum.

Based on the test work and field trials carried out to date, this material offers the operators increased flexibility by providing a coating system, not only resistant to immersion in process fluids at elevated temperature, but which also overcomes many of the other problems associated with the use of coating systems in this type of service.

In addition, its success in high temperature service offers an attractive option for new build vessels, allowing manufacturers an alternative to more expensive corrosion resistant alloys. A classic example of this is an application in Brazil to four new build pressure vessels in 2009. Each vessel weighed 70 tonnes, with a total internal area of 1,100 sq m. Pressure vessels required a corrosion-resistant coating able to resist high in-service temperatures of up to 180°C. Adjacent flange faces and nozzles also required corrosion protection. The Belzona system was chosen due to its excellent heat resistance properties and proven longevity. An inspection carried out in January 2013 concluded that the lining was still in service with no remedial work necessary. Installed Belzona nozzle inserts and Belzona-formed flange faces were also in perfect condition.

Whilst initially designed for the offshore industry, the high temperature performance of this product makes it suitable for a wide variety of applications within the oil & gas, petrochemical, power and paper industries, as well as others with high temperature erosion/corrosion problems.

Belzona 1591 (Ceramic XHT Metal) principle advantages include: 6 High temperature resistance, suitable under full immersion resistance in water/hydrocarbon mixtures up to 180°C. 6 Resistance to explosive decompression.

6 Binary curing mechanism removes the need for extensive post cure prior to entering service.

6 Application in confined areas due to a solvent-free formulation.

6 Ease of application to either new-build or existing vessels combined with easy repair in-situ.

Belzona is committed to continuing product improvements, taking into account feedback from the field in order to optimise application delivery. This initiative is supported by an ongoing investment in Research and Development, and the department is currently finalising work on the next generation of high temperature lining materials designed to provide long-term corrosion protection whilst minimising downtime and being easier to apply to consistently high standards. ■

Belzona Technical Services

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Technology

All naval architects are looking to design smarter, greener, safer and cleaner ships, reducing emissions to meet stricter environmental controls. Nicholas Newman looks at some of the present trends.

Drivers for

tanker design A

ROUND 90 PER CENT of the world’s trade in goods is carried by sea. According to Shipping Intelligence Weekly, there were approximately 58,000 cargo carry ships operating in June 2012. It has been calculated that maritime shipping is responsible for emitting more than 1bn tonnes of carbon dioxide (CO2) per year accounting for more than three per cent of worldwide CO2 emissions in 2007. The oil tanker fleet was responsible for some 12 per cent of total CO2 emissions by global shipping, reported the International Maritime Organisation (IMO) in 2012.

Currently, the global maritime industry’s ships and tankers rely on engines fuelled by heavy bunker oil and diesel. However, a combination of rising oil prices and ever stricter environmental regulations have raised operating costs driving ship owners to demand greater fuel efficiency, lower emissions and faster turn-around times in port.

Currently about 240mn tonnes of LNG is shipped worldwide annually in a fleet of some 357 carriers (Lloydsintelligence.com 16 September 2013) from centres of production including West and North Africa to East Asian markets which accounted for more than half of total global LNG demand in 2012.

Globally the construction of LNG export plants in Australia, Mozambique and Tanzania, with possible exports from the United States, will add at least 93.5mn tonnes of capacity and accounts for the 94 LNG carriers currently on order for delivery between now and October 2017. Nigeria has ordered six new LNG carriers for delivery from 2017 to add to its current fleet of 24. Not only is the worldwide LNG carrier fleet increasing, but the size of tankers is also rising. The biggest new tanker, the Q-max, holds up to 260,000 cu m compared with the typical tanker of around 175,000 cu m (Ernst and Young).

Tankers move approximately 2,000,000,000 metric tonnes of oil every year. Currently, the market is experiencing a surplus of tanker capacity caused, in part, by too many tankers having been built in the run-up to the global financial crisis and subsequent economic slowdown and the shale energy revolution which has significantly reduced North American reliance on imports of oil and gas.

The Eco bank has reported that demand for Nigerian oil from the USA declined to 700,000 bpd in 2013, from the 2012 average of 800,000 bpd.

Likewise, Bloomberg reported 3 September 2013, that Chinese refiners will buy 28 per cent less West African crude this month than a year earlier. For Nigeria, these trends have reduced the use of the 200,000 DWT Suezmax and the 120,000 DWT Aframax oil tankers, which serve the North Atlantic

64 Oil Review Africa Issue Four 2013

Wärtsilä’s new Aframax tanker concept design.

The GL BEST PLUS hull design concept for the Aframax tanker, is said to reduce fuel use by seven per cent. trade whilst recent increasing demand from Asian markets encouraged a switch to the use of larger 315,000 DWT Very Large Crude Carriers (VLCCs). As a result, daily earnings for VLCCs have plunged 92 per cent this year, to some US$1,515 on 30 August, according to shipbroker Clarkson plc. Rising operating costs, an increase in LNG capacity and new sources of supply together with newly emerging markets for LNG in India, Latin America and Caricom affect the size of the LNG fleet. Similarly, changing patterns of demand and supply of oil is driving fleet owners to seek much more cost effective designs in the next generation of oil tankers.

the frictional resistance of the ship as it moves through water and, as a bonus, reduce fuel use.

Companies such as Mitsubishi Heavy Industries are revisiting this concept but, a representative for the Royal Institution of Naval Architects commented to me, “They have been trying to make this technology commercial for more than 50 years.” By contrast, the Marine Research Institute of the Netherlands is trying to develop more energy efficient rudder and propeller designs in order to reduce unwanted noise and vibration. In addition, designers are experimenting with adding fins or stabilisers: these are designed to either enhance how the water passes through the propellers or, to enhance the overall hydromantic nature of the ships design in order to cut drag and thereby save on fuel. Another approach, proposed by Skysails GmbH & Co of Hamburg is the use of sea kites to pull ships along.

A vessel equipped with SkySails could require between 10 to 35 per cent less fuel than a nonfitted vessel, claims Skysails.

Smarter shipping At present, all naval architects are looking to design smarter, greener, safer and cleaner ships. This is especially the case with tankers, whatever their size or cargo. Smarter shipping is about optimising the hull shape in such a way that it minimises drag whilst, at the same time, optimising cargo capacity.

For example, the GL BEST PLUS hull design concept for the Aframax tanker, is said by its designers, GL and the National Technical University of Athens, to reduce fuel use by seven per cent. Another idea is that of the Slippery ships concept, in which the vessel is designed to float on a cushion of air. Here a device on the ship’s keel makes bubbles to reduce

Greener shipping Greener shipping is about reducing emissions to meet stricter environmental controls. The simplest way of reducing emissions is to reduce speed.

However, Europe’s stricter emissions regulations have driven investment in “cold ironing” and the use of expensive low sulphur fuels when in port.

Since 2010, vessels berthing for more than two hours have had to switch to a 0.1 per cent sulphur fuel or switch off all engines and hook up to shore side electricity to keep essential on board electrical equipment, ranging from refrigeration, lighting and heating running. Upcoming regulations

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Technology

Germanischer Lloyd unveils energy efficient Aframax BEST-Plus ship design.

The use of LNG-fuelled shipping is limited by constraints of space and lack of a network of LNG fuelling stations worldwide. for the trans-European transport network (TEN-T) are also likely to include shore connections in port modernisation programmes.

Whilst heavy fuel oil and diesel engines dominate the tanker market, rising costs and increasingly strict environmental regulations have led to consideration of alternative fuels including premium low sulphur fuels, nuclear power and, with the rise in LNG production and trade, LNG. Dual fuel engines which allow the use of both diesel and gas and LNG fuelled vessels are recent innovations. As of

June 2012, there were around 300 ships worldwide powered by LNG, of which 240 were dedicated carriers of LNG (Zeus Intelligence). The remaining sixty vessels comprised platform support vessels, passenger and cargo ferries and coast guard patrol ships based mainly in Scandinavian waters. Already, Wärtsilä, a world class engine maker, has begun to fit Wärtsilä 8L50DF 1 dual fuel engines to tankers.

These engines can operate on either natural gas, light fuel oil (LFO), or heavy fuel oil (HFO) and switching between fuels can take place seamlessly during operation without loss of power or speed.

When operating in gas mode, the nitrogen oxide (NOx) emissions are at least 85 per cent below those specified in the current IMO regulations and CO2 emissions are some 25 per cent lower than those of a conventional marine engine running on diesel fuel.

Additionally, the sulphur oxide (SOx) and particle emissions are negligible at almost zero per cent. The

fitting of Wärtsilä 50DF engines on-board the first LNG carriers in 2006 set a trend in the industry. Since their introduction, 65 per cent of all new LNG Carriers have been fitted with Wärtsilä dual-fuel engines. An increasing number of vessels serving the offshore oil and gas industry are being fitted with Wärtsilä dualfuel engines. The need for flexibility, fuel efficiency, and compliance with stricter environmental regulations, are the drivers behind this trend.

However, the use of LNG-fuelled shipping is limited by constraints of space and lack of a network of LNG fuelling stations worldwide. LNG fuel tanks are rather large which is not a problem for a VLCC nor a LNG fuel carrier but is a restriction on traditional marine cargo vessels. A more serious constraint on LNG marine fuel for non-LNG carriers is that besides Scandinavia, there is a scarcity of LNG bunkering services around the world. To cater for the expected increase in LNG marine fuel use, major ports including Zeebrugger, Rotterdam, Hamburg, Singapore and New York have publicly announced that LNG fuelling facilities will be ready from 2014.

Conclusion It is likely that, as the implementation of worldwide environmental restrictions on coastal waters progresses, the number of ships equipped with dual fuel engines capable of using LNG as a marine fuel will increase. LNG is both cheaper and cleaner than currently used fuels. LNG as a marine fuel meets IMO Tier III and ECA limits for sulphur dioxide, nitrogen oxide and carbon dioxide. For those looking for a diesel engine to propel their next oil tanker, many are selecting single engine designs such as the Wärtsilä-Sulzer RTA96-C turbocharged two-stroke diesel engine, which are ideal to power for the next generation of larger oil tankers. It is clear that the shipping industry is on the cusp of major technological and design innovations. ■

ABS forms global gas solutions team GREENFIELD GAS PROJECTS off the east coast of Africa have been fuelling services demand, according to Karel Van Campenhout – ABS regional vice president for Africa and senior vice president for ABS Europe.

In emerging markets like East Africa, class societies are an integral part of the verification process to establish acceptance criteria for the design integrity of vessels, risk mitigation and offshore safety.

As a non-governmental organisation working closely with industry and regulators, the American Bureau of Shipping (ABS) provides and maintains the technical standards for the construction and maintenance of offshore vessels and facilities by validating through routine surveys that these structures are in accordance with certain rules and guides.

In West Africa, 65 per cent of drilling units operating in the region are classed with ABS. The organisation has the largest market share for the number of floating production units

66 Oil Review Africa Issue Five 2013

under ABS class in the region. East Africa will also require an influx of classification and technology services to lay the foundation for multibillion dollar LNG projects.

ABS is joining the move eastward with plans to expand its coastal network by opening operating bases in Pemba, Mozambique, and Mombasa, Kenya, in late 2013.

Mozambique recently inaugurated the country’s first oil port in the city of Pemba. In the last year, Anadarko has built additional infrastructure at Pemba, now the central location for embarkation to offshore units operating in the area, where technical support for large-scale projects, including a proposed LNG plant, will be needed. ABS has identified this port city as its primary location in East Africa, where it will offer services to support offshore and marine operations.

Although Kenya has a modest upstream industry today, the government is encouraging foreign investment in petroleum exploration.

The port of Mombasa traditionally has been the major trade gateway to East and Central Africa, handling some 20mn metric tons of cargo in 2011.

Construction is under way on a megaport at Lamu in northern Kenya, East Africa’s largest infrastructure project, including improvements to rail and road networks. To meet future demand for more services in the region, ABS is finalising plans to establish an office in Mombasa with closer access to other coastal port cities.

With East Africa a major growth area for the offshore oil and gas industry, ABS’ long-term focus will be to improve service delivery while these massive investments are directed into ports and infrastructure along the coast.

As development continues to accelerate, the organisation will work with industry and regulators to develop technical standards through established rules and guides that promote the security of life, vessel and the natural environment. www.oilreviewafrica.com

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Technology

Heat rate reduction kit MAGNETROL INTERNATIONAL HAS introduced the heat rate reduction kit, aimed at helping power companies manage controllable losses through effective, accurate feedwater heater level control.

The heat rate reduction kit is available for download at www.heatrate.magnetrol.com and addresses the mission-critical need to increase the efficiency of power plants in today’s challenging economic and regulatory environment. The heat rate reduction kit, an industry first, provides solutions that will help reduce fuel expenditures, which can account for 70 to 80 per cent of production costs, by minimising heat rate. According to Magnetrol, the potential savings represent an estimated US$680,000 annually for a 500 MW power plant.

Included in the Magnetrol heat rate reduction kit are several useful guides to reducing heat rate, why it is important and how the process will help reduce costs: 6 Heat rate and feedwater heater level control white paper 6 Managing heat rate and controllable losses video 6 Next-generation level instrumentation for heat rate awareness and control special applications bulletin 6 Reduce your heat rate and drive down fuel costs brochure “We created the heat rate reduction kit because we recognise the challenges power companies face today in an increasingly competitive environment and with the advent of climate change protocols and the Clean Air Act,” said Magnetrol's product manager Jim Homoly. “The kit explains how minimising heat rate can help plants use energy more efficiently and save significant fuel expenditures.”

The causes of heat rate inefficiency can be due to ageing level instrumentation or instrumentinduced errors, which negatively impact heat rate and fuel costs, according to Homoly.

“Effectively controlling feedwater heater levels drives overall plant performance and fuel cost savings,” he said.

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Technology

Expro's "SafeWells" well integrity management software can be used to monitor well integrity performance, send real time reports, highlight problems and prompt remedial actions. One client that has benefited from this well integrity expertise is Tullow Oil.

SafeWells software solution for effective well

integrity data management I

N THE CURRENT oil and gas environment there is a growing requirement for oil and gas companies to operate in accordance with their well integrity policies, statutory regulations and various international standards.

The driving factor behind the change is directly linked to more strictly prescribed legislation and corporate social responsibility following high profile well integrity related incidents.

Clearly when fields were first being produced there was less emphasis on longevity with well lifecycle management, a term only more commonly used in recent years.

Typically, companies predicted a lifespan of The SafeWells sofware solution is fast becoming the established industry benchmark, seen here with Expro’s Simon Copping.

between 15 and 20 years for their wells when in reality many are still fully operational three decades later.

In the wake of the increased operating period there is demand for well integrity standards to be far more robust.

Commitment to well integrity now forms a large part of strategic planning and budgets, with wells subjected to annual and independent audits that provide key performance indicators for future planning.

Service companies have identified well integrity as a growth market sector and have invested heavily in developing sophisticated solutions to addressing this industry-wide issue.

Service companies have identified well integrity as a growth market sector and have invested heavily in developing sophisticated solutions to addressing this industry-wide issue.

Expro is one such market leading company in this niche sector of well integrity and its tailored software solution SafeWells is fast becoming the established industry benchmark.

SafeWells monitors and reports on well integrity performance and has been successfully deployed by a wide range of independent and major operators across the globe.

The highly flexible software, which can be bespoke tailored to client needs, allows the monitoring of maintenance and associated remedial actions, risk assessment needs, dispensations and changes in the well operating envelope.

This provides an onscreen traffic light display of well status according to designated well failure models and also the ability to communicate through email the same status to any number of chosen personnel.

Operators can therefore plan their well intervention activities safe in the knowledge that they are compliant with their policies, while being able to demonstrate effectiveness at monitoring and tracking their wells' status.

SafeWells development began in 2005 and over the last three years Expro has added more focus on the software development as the number of clients using the products has risen.

In line with the growing popularity of the product the overall need for well integrity management systems within the industry has also increased.

The software has been well received globally with Expro building a specialist team in North America to further increase its capabilities.

Tullow’s eperience One client that has benefited from Expro’s well integrity expertise is Tullow Oil. The major independent oil company made substantial oilfield discoveries in both Ghana and Uganda and as a result needed to further develop its well integrity procedures. More specifically Tullow Oil had to be prepared for this major

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The consequences of bad well integrity management can be environmentally devastating.

Tullow has made substantial discoveries in Ghana.

improving the company’s well integrity performance.

“This provides a direct impact on communication, safety performance and the overall bottom line.

“Initially Tullow required a centrally managed integrity system to monitor its worldwide operations covering onshore and offshore wells including subsea completions.

“SafeWells was originally rolled out on Tullow’s Bangora Gas Field in Bangladesh and is now deployed on its UK and Ghana operations.

“So far this product and the team supporting it have fulfilled all of our own expectations as well as receiving positive client feedback.

“I am excited about making a difference to our industry and building on the foundations of the success we have already enjoyed with SafeWells.”

Copping also commented on the broader industry issue of well integrity management.

He added: “The consequences of bad well integrity management can be environmentally devastating and have a severe impact on corporate reputation.

“The lifeblood of an oil and gas company is ultimately the revenues it generates through production, so having unplanned production downtime due to well integrity issues can have major financial implications.

“Well integrity software is helping to address these challenges.”

Operators are faced with the challenging problem of meeting production targets while ensuring that their wells continue to operate safely.

“Tubing and component selection typically is made based on the expected life of the well.

However, it is often the case that wells are in operation far longer than originally planned and that the nature of well fluids changes over time, further compounding the problem.

“Clear integrity management systems provide guidelines that help ensure personnel at the well site are kept safe.

“Importantly, they constitute a reusable set of policies and procedures that ensure wells are properly and routinely tested.”

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Oil Review Africa Issue Five 2013 69

Technology

predicted increase in oil production.

In partnership with Expro, Tullow has developed a well integrity management system (WIMS) and implemented SafeWells.

Simon Sparke, well integrity manager at Tullow Oil, and his team began using SafeWells in 2010.

Since then, they have enjoyed an excellent working relationship that has led to significant developments in the software.

“Tullow is very happy with our well integrity management system and this has been made possible with the ease of developing the software in partnership with Expro,” he said.

“Linking various software packages to SafeWells allows my team to monitor all our operated wells.

Through the highly visual process of displaying the status of any of our wells, we report monthly to various managers on our well stock and the various safety critical components in the wells.”

Expro’s Simon Copping, SafeWells product manager, who worked closely on the Tullow project picks up the case.

“We have a fantastic software system in SafeWells that really complements Tullow’s well integrity strategy,” said Copping.

“With different types of wells in challenging engineering environments operating under a range of governmental legislations, having a software package that is user friendly and flexible is key to

Technology

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working in partnership with Expro to deploy its SafeWells system?

Instant overall visibility saves time From a visualisation perspective, it provides an instant overview of well integrity statuses across all assets.

This is done through a green, yellow and red traffic light system that alerts users to potential integrity issues with a well.

The visibility to the organisation not only gives customers quick access to current well statuses, but having this system in place has associated cost saving benefits as well.

One customer has saved 97 per cent of the time it takes to run well integrity reports across all of its assets. In real time that has condensed the job time to just two hours, which previously took two weeks.

This visualisation system helps to alleviate the associated problems so more people can find out what is going on with a well and do so in a fraction of the time.

SafeWells is also an extremely flexible piece of software that allows clients to customise operating parameters that are unique to its policies and procedures as well as updating those when specific information such as corrosion of tubing is available.

Additionally, the software complements other

services Expro offers especially around well integrity and well intervention services.

To further contextualise this, well integrity is defined by NORSOK D-010 as the “Application of technical, operational and organisational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well.”

In more simplistic terms, it is about identifying and prohibiting leaks.

SafeWells is set up to alert users when operational parameters fall outside of acceptable ranges. When these issues are detected, customers trigger dispensation procedures into action.

This is part of the added value of SafeWells especially as customers are made aware of any issue before it becomes a significant problem that requires automatic shut-in, meaning they can minimise unplanned production downtime.

Saving time and money One client slashed unplanned downtime by 50 per cent thanks to SafeWells.

In terms of production, a particular well intervention activity took two days to carry out when it was planned and four days when unplanned.

Those additional days of gained production time amounted to more than US$150,000 savings because the well was kept online.

For example, if an annulus pressure test fails and

In more simplistic terms, it is about identifying and prohibiting leaks. the customer suspects tubing corrosion, a caliper log can be run to determine how much tubing thickness loss there might be due to corrosion.

Downhole video cameras also have similar applications in that they literally allow customers to see first hand what might be causing the well integrity problem.

Expro also has expert well integrity engineers who consult with customers on developing WIMS policies and procedures.

By having these in place prior to implementing SafeWells, the customer already has the rules and guidelines for the system to operate, such as acceptable leak rates.

There is little doubt SafeWells is a valued market product particularly as it integrates with a host of Expro’s other products and services.

The flexibility of SafeWells allows customers to customise the information they need to see. The way the data is visualised means it is easy for companies to turn their well integrity status into a real-time picture that improves decision-making and helps companies to achieve targets, key performance indicators and standards in well integrity. ■

In honour of the 35th Anniversary of the Foundation of the Ministry of Petroleum Republic of Angola

Angola International Oil & Gas Conference and Exhibition

25 – 26 November 2013

Epic Sana Luanda Hotel, Luanda, Republic of Angola

Utilising and Identifying new Oil & Gas resources for the benefit of Angola’s future generations

www.aiogace.com Organised by:

Silver Sponsor

REPÚBLICA DE ANGOLA MINISTÉRIO DOS PETRÓLEOS

70 Oil Review Africa Issue Five 2013

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Technology

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Drilling in environmentally sensitive areas of East Africa requires operators to consider both technical and environmental criteria when treating and disposing of cuttings and excess drilling fluids. In less technically demanding exploration wells, Tullow Oil sought drilling fluids with green credentials, but recognised that a system with improved technical performance was necessary to drill more demanding, high angle and extended reach wells.

Drilling fluid selection for environmentally

sensitive areas I

N A THOROUGH study of shale characterisation and inhibition testing, seven drilling fluids—including six waterbase muds (WBM) and one synthetic-base mud (SBM)—were evaluated to determine a simple ranking for technical and environmental performance as well as treatment and disposal options for each fluid.

The SBM was the strongest technically, followed by an amine-modified high-performance WBM system. Both systems can be combined with technoeconomically feasible treatment and disposal options that minimise environmental impact.

Introduction Tullow requested a fluid selection study with cores from fields of interest. The study was conducted to support the drilling fluid design and recommendations for future development of an East African basin. A total of 108 core samples were available, with 15 selected based on depth and fields with the most similar properties as the zones of interest.

Selected core samples from two wells were used to evaluate the rock/fluid interaction of formation samples with different drilling fluids.

Six laboratory techniques evaluated the stability of the rock samples. Samples from Well A were used for testing with base fluids (brines) and the samples from Well B were used for testing with the fully formulated drilling fluids.

Testing was split into two phases, with the first examining formation material and surmising

the best fluid-rock interaction. The second phase determined the rock behavior with the selected fluids.

Shale characterisation In Phase 1, shale characterisation was determined by the shale mineralogy and Cation Exchange Capacity (CEC) data using the semi-quantitative XR Diffraction (XRD) analytical method. These tests provided information on minerals and their relative abundance in the shale and shale reactivity. Thin section analyses of core samples from the field provided a more qualitative description of the rock with respect to principal mineral, mineral with distribution of the rock, qualitative description of the rock, presence of fractures and orientation, and grain size ranges.

Phase 2 included a shale inhibition and stability study. With the XRD/Thin Sections and CEC results, the fluid formulation was optimised for enhanced shale inhibition study. Tests to evaluate the formation and drilling fluids included examination of bulk hardness, dispersion testing, accretion testing, linear swelling,

Common elements of concern were found in drilling and completions fluids when assessing the environmental impact of the waste.

immersion testing, capillary suction tests, X-Ray Diffraction, and CEC. Fluid systems for study included: 6 Fluid 1: Fresh Water/PHPA/PAC/XCD WBM 6 Fluid 2: Fresh water/potassium Acetate/PHPA/PAC/XCD WBM

6 Fluid 3: Amine-base high performance WBM 6 Fluid 4 : SBM 6 Fluid 5: High performance WBM-low conductivity (modified amine)

6 Fluid 6: Fresh water/potassium chloride/PHPA/PAC-polymer mud

6 Fluid 7: Fresh water/low potassium acetate/PHPA/PAC/XCD polymer WBM The team applied elements of several quality targets from various published discharge guidelines in the country and also applied internationally recognised treatment targets for determining the appropriate conditions of solid and liquid effluent released to land and water. Regulatory guidelines allowed the team to compare the fluids against a benchmarked goal during development and assessment.

Common elements of concern found in drilling and completions fluids when assessing the environmental impact of the waste included: total suspended solids (TSS), salts/ions, hydrocarbons, heavy metals, waste minimisation and treatment of the waste, the methods available to treat the wastes, and identifying benefits of the treatment.

To consider environmental impacts, the study

Figure 1:Drilling fluids selected for study, including drilling performance and environmental rating.

72 Oil Review Africa Issue Four 2013

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Technology

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focused on the two phases of the system, the solid cuttings and the liquids (mud and water) that are used, separated and disposed of during the operation.

Immersion test For the immersion test, the sample in the paraffin-base oil was not affected by the fluid. The sample in the 10 per cent KCl was the less affected for water-base fluids. Immersion testing showed that 10 per cent KCl minimum was needed to keep the sample intact. The addition of amine improved inhibition. The paraffin-base oil showed the best inhibition.

Fluids containing amine and the SBM showed no or negligible accretion. The potassium acetate/low molecular weight PHPA (LMW-PHPA) exhibited 8.1 per cent accretion while the freshwater/low molecular weight PHPA fluid showed 37.2 per cent.

Bulk hardness testing showed that Fluid 4 and the Fluid 3 system exhibited the best results. High dispersion tendency in freshwater and a significant increase in recoveries were obtained with the drilling fluids. Data showed that the PHPA/PAC system had the lowest performance.

Lowest conductance was exhibited by Fluid 4 and the high performance Fluid 5, 0.5 ÎźS/cm and 1.2 mS/cm, respectively. The lowest Capillary Suction Test (CST) values were obtained utilizing fluids: 5 ppb potassium acetate in freshwater, 25ppb potassium acetate in freshwater, and 25 ppb (seven per cent wt) KCl. Thin sections analyses indicated pore sizes mainly ranged from 50 to 130 microns. The maximum pore size is ~150 microns. XRDs showed that the formation consisted mostly of quartz and kaolonite. The cores were unconsolidated plugs with the presence of clay. The presence of kaolonite is generally the cause for fines migrations when producing the well.

A variety of fluids were considered technically capable of drilling the zone, but the team questioned whether their environmental rankings complemented the practicality after considering constituents of concern in each fluid, the total waste volume and the treatment options. The fluids all shared many of the same components

Figure 3: Visual depiction of accretion results for Fluids 1-4.

74 Oil Review Africa Issue Five 2013

Figure 2: Accretion results for Fluids 1-7.

Fluids were assessed based on their components before coming into contact with the formation. with one or two substitutions that affected fluid property changes in terms of technical and environmental performance.

Fluids were assessed based on their components before coming into contact with the formation, which could contribute additional contaminants not contained in the products, but that could negatively alter the environmental ranking.

Fluid rankings Fluid 1 was given an environmental ranking of an A because of its low electrical conductivity (ion content), the high potential for biodegradation of the suspended solids in the form of polymer, and the minor impacts that would occur from an unplanned release or spill of the fluid. Negative points were given because of the potentially large

volume created and required for disposal.

Fluid 2 received a D ranking. Although it has a high potential for degradation and a high rank for inhibition, the electrical conductivity is very high, especially in the liquid phase. With low intensity treatment on site it would take several months to treat the water to acceptable discharge levels, making it impractical for operations.

Fluid 3 received a B ranking. The electrical conductivity is originally much lower than the acetate while still providing good inhibition.

However, the fluid would need to be treated to remove residual conductivity and the biochemical oxygen demand (BOD) and chemical oxygen demand (COD). The treatment may not be able to achieve the low values set for water discharge in a reasonable timeframe.

Fluid 4 had a rating of 10. Lab tests indicated that the SBM provides a very high amount of inhibition. The expected washout in the hole would be very low (roughly 10 per cent or less depending on the formation), greatly reducing the cuttings generated. With the high inhibition, the amount of dilution to maintain the low solids in the active mud system should be low and solids control should be able to remove the majority of solids, allowing the base mud to be reused for other wells.

A rating of nine was given to Fluid 5 as the lab test indicated that the amine-base high performance WBM provides a high amount of inhibition. The expected washout in the hole would be in a low range (roughly 15 per cent or less), reducing the cuttings. With the high inhibition, the amount of dilution to maintain the low solids in the active mud system should be low.

A rating of eight was given to Fluid 6. Lab tests indicated that Fluid 6 provides high inhibition. The expected washout in the hole would be in a low range (15 per cent or less) with reduced cuttings and low dilution required to maintain low solids.

The environmental ranking is a D due to the high initial electrical conductivity of the fluid and the low potential for biodegradation of the ions once they enter the environment. The ranking also

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THE UNITED REPUBLIC OF TANZANIA

Announcing the 4th Tanzania 2013 Licensing Round Deep Offshore | North Lake Tanganyika

The Government of the United Republic of Tanzania through Tanzania Petroleum Development Corporation (TPDC) is pleased to announce the 4th Tanzania Deep Offshore and North Lake Tanganyika Licensing Round.

The delayed 2012 round was launched during the 2nd Tanzania Oil and Gas Conference and Exhibition.

Round Close:

Thursday, 15 May 2014, Dar es Salaam

4TH TANZANIA OFFSHORE AND NORTH LAKE TANGANYIKA LICENSING ROUND

The round includes the deep offshore sedimentary basins comprising of seven blocks (averaging 3000 sq km: Blk4/2A, Blk4/3A, Blk4/3B, Blk4/4A, Blk4/4B, Blk4/5A, Blk4/5B) and is located between 2000 m to 3000 m of water depths from 40°30’E to 41°40’E and 7°30’S to 9°00’S. Blocks 4/1B and 4/1C are reserved for the TPDC to execute exploration using a strategic partner. The blocks have excellent coverage of modern regional 2D seismic data available from ION Geophysical and WesternGeco.

The North Lake Tanganyika block is located offshore in the western arm of the east African rift system. Lake Tanganyika is the world's longest (650 km) and second-deepest (1500 m) and is covered by sparse 2D seismic data collected in the 1980s during the African Lakes Drilling Project. The data and copy of report will be made available.

Tanzania Petroleum Development Corporation Contact: Mr. Yona Killagane Email: tpdc4round@tpdc-tz.com

ION Geophysical, Inc.

WesternGeco

Contact: Nick Blake Phone: +44 7734 415105 Email: nick.blake@iongeo.com

Stewart Walter Phone: +44 1293 556533 Email: swalter@exchange.slb.com

www.tz-licensing-round.com

Technology

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Figure 4: Visual depiction of accretion results for Fluids 5-7.

Lab tests indicated that the SBM provides a very high amount of inhibition. reflects the lack of adequate treatment to remove the source of contamination.

The rating of eight to nine in lab tests of Fluid 7 indicated that the WBM provides a high amount of inhibition with an expected washout in the hole of 15 per cent or less, with reduced cuttings and a low amount of dilution required. The fluid was given an environmental ranking of C. Even after lowering the potassium acetate content the initial exchange capacity was still high. The minimisation of the additive improved the ranking from the previous formula. A biological treatment onsite is required before discharge. The acetate is organic and will biodegrade. There is minimal waste generation. A summary of environmental and drilling performance can be seen in Figure 1.

Recommendations Drilling performance of the fluids was evaluated on the shale inhibition (bulk hardness, dispersion, accretion and swelling tests) results while the environmental evaluation was based on chloride content, conductance and waste disposal methods.

From the summary of the results of the different shale inhibition testing with all the fluids, the Fluid 4 was rated 9.7 of a maximum 10 points as the most inhibitive drilling fluid, followed by Fluid 3 rated at 8.0.

Fluid 6 was rated 6.5, while Fluid 5 was rated 6.4 and Fluid 6 scored 6.0. Fluid 7 scored 5.6, whereas the least inhibitive WBM, scoring 2.8, was Fluid 1.

Treatment and disposal Dewatering and water treatment can be utilised on location to reduce waste generation and recycle water on location for Fluid 1. Treatment of mud to releasable water would be reasonably easy. Some treatment for excess polymers and some aeration may be required to attain most regulatory parameters for release.

76 Oil Review Africa Issue Four 2013

Unless a significant amount of barite has been used and high levels of heavy metals are detected, then the cuttings can be blended with soil and land farmed or buried with little to no impact due to contaminants. Cuttings with barite may require some blending with soil to reduce the concentration to an acceptable level.

For Fluid 2, the dewatering and water treatment process will not remove the excess acetate in the treated water, requiring a secondary bioremediation and aeration process that can take as long at 20 to 45 days per batch. Onsite and timely treatment may require a centralised treatment plant to treat high concentration potassium acetate mud. Drill cuttings will retain a level of potassium acetate that can be bio-remediated with some soil blending and soil enhancement with amendments.

For Fluid 3, onsite dewatering and water treatment will not remove the amine in the treated water, which would have a conductivity level of 6,000 to 8,000 mS/cm, above the suggested level of 2000 mS/cm or lower in many countries. Past projects have shown that a dilution of 70 +/percent will bring the conductivity to a level of 2,000 mS/cm. Aeration can assist in reducing the amine but will take time. If dilution can’t be performed, a secondary bioremediation process will be required to promote the removal of the amines in the water. The drill cuttings will retain a low level of amine that will be able to be bio-

remediated with some soil blending and soil enhancement with amendments. Burial of the stabilized cuttings can be done with quick lime, cement or fly ash.

For SBM fluids such as Fluid 4, solids below 10 microns and the water phase can be removed with a chemical additive and centrifugation. Commercially available systems can recover base oil from used mud. Drill cuttings with SBM can be bio-remediated.

Other options for cuttings treatment or disposal are thermal treatment and waste injection, or even stabilisation/solidification. Waste injection disposes of all OBM waste fluids and cuttings.

For Fluid 5, onsite dewatering and water treatment process will not remove the amine in the treated water, thus there will be a conductance level of 2,000 +/- mS/cm, which is in the range for discharge in many countries. Drill cuttings will retain a low level of amine that can be bioremediated with some soil blending and soil enhancement with amendments. Stabilisation/ solidification is a feasible option.

For Fluid 6, high chlorides not removed through onsite dewatering and water processing must be reduced by reverse osmosis or distillation. However, both create a high-chlorides sludge for disposal.

Dilution would require rates of 60 to 70 to one or more, which is not feasible. High chloride fluids and wastes can be disposed of through injection. Drill cuttings will retain a level of chloride that will be inhibitive to bioremediation.

For Fluid 7, a secondary bioremediation process will be required to remove acetate in water treated on site, which can take 20 to 45 days per batch. A centralised treatment plant may be required to treat high concentration potassium acetate mud. Drill cuttings will retain a level of potassium acetate that will be able to be bio-remediated with some soil blending and soil enhancement with amendments.

Conclusion Based on the above analysis, Fluid 4, the SBM, was the strongest technically, followed by Fluid 5. It was shown that both can be combined with technoeconomically feasible treatment and disposal options that minimise environmental impact. ■

Authors: Paul Burden and Klisthenis Dimitriadis, Tullow Oil; Kayli Clements, Chau Nguyen, Tony Staples, Seye Thomas; M-I SWACO, A Schlumberger Company

GE’s subsea signal detector creates ripples GE’S MEASUREMENT AND control subsea condition monitoring system, also known as the Cage, has made a mark in the oil and gas subsea sector.

Cage is equipped to measure sound and electrical signals emitted from subsea equipment, often an early warning sign of developing leaks and other issues. The listening ‘ear’, which is an array of sensors in a 228-kg birdcage dome that sits on the sea floor or on subsea equipment was developed at the GE Measurement and Control site in Bergen, Norway. A 210metre deep water facility there also provided deep water testing for the technology.

Engineers designed the eardrum of the system from special crystals that respond to sound wave vibrations and convert then into electricity. A single device can listen to sounds within a 488-metre radius. In addition, an array of attached carbon rods can detect changes in the magnetic field and spot ground faults or defective isolation. www.oilreviewafrica.com

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Innovations

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Gamma Ray Isotope projector manufacture begins in South Africa GAMMATEC NDT, A subsidiary of NTP accreditation, as well as the approval Radioisotopes SOC Ltd (NTP) and part of the under the license of EMI to manufacture South African Nuclear Energy Corporation the Oserix Exertus Range of Gamma Ray (NECSA) Group, has announced that the projectors in South Africa.

Exertus DUAL 120 Gamma Ray Projector "The challenges Gammatec NDT faced would be manufactured in the country. included producing a world-class In 2010, Gammatec NDT led an initiative to product under stringent controls and at establish a joint venture with two private a reasonable price to ensure global entrepreneurs, which saw Oserix SA sign an competitiveness," Davies added. exclusive supply contract with Russian "Various manufacturing options were gamma technology design and manufacturing investigated prior to the purchase and company Energomontage International (EMI) installation of a new state-of-the-art 5 to take ownership of the Exertus Range of axis, multi-tasking CNC machine to be Gamma Ray Projectors. Gammatec became able to manufacture the majority of the sole distributor for Oserix SA in South components. Supply contracts were Africa, the Middle East and South East Asia. also negotiated and formed for other The Exertus DUAL 120 Gamma Ray projector from Gammatec NDT. (Image source: Gammatec NDT) "Aggressive sales and marketing, plus the fact key components including the supply of that a number of the current gamma ray projectors depleted uranium shielding from NTP utilised in our industry are reaching the end of their life span due to Radioisotopes SOC Ltd," he added. expiration of their Competent Authority Certificate, has resulted in early Over the past 30 years, Gammatec NDT has become a leading supplier success in the supply of the new gamma ray projectors," said of Non-Destructive Testing (NDT) equipment, accessories and Gammatec NDT group managing director Ralph Davies. consumables. From its head office in Vereeniging, South Africa, the Gammatec NDT began the stringent approval process for the product company exports to more than 60 countries around the globe. three years ago, which included a detailed QA/QC work flow procedure, The company will now target the production of additional models of the staff recruitment and training, and high-end technology machinery Oserix Exertus range of gamma ray projectors from its South African investment. Gammatec NDT was awarded with ISO 9001-2008 manufacturing facility.

78 Oil Review Africa Issue Five 2013

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CONFERENCE AND EXHIBITION

21-23 JANUARY 2014

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ICT

When BP in Cairo decided it needed reliable high-speed connections between its various offices, it chose a wireless technology that may be unfamiliar to some readers. However, use of free space optics (FSO) is growing, as Vaughan O’Grady finds out in the first of two articles on how technology is meeting the communications needs of modern businesses.

From the wellhead

to the rooftop “W

E REALISED PEOPLE would be reliant on these things — that downtime would be abhorrent. So we had to do three things. One was to design a product that was the most reliable possible and wouldn’t fail. Second to only sell it in environments to which it was suited. And lastly to make sure it’s backed by resellers who can provide any service the customer needs.”

We are talking here about communications. Or, more accurately, Stephen Patrick is the CEO of Wireless Excellence Ltd, a leading designer and manufacturer of professional wireless products for a wide variety of applications. That includes Wi-Fi, WiMAX, microwave, millimetre wave and more.

‘More’, in this case, includes free space optics (FSO), which uses infra-red laser technology to transmit data. The focus on FSO in this article is because BP in Egypt has chosen what may, to many readers, be an unfamiliar wireless technology to send data to and from its various Cairo offices.

All our wireless links are up on rooftop level, and mounted in locations where there is clear line of sight between locations.

Why BP chose the technology As for why it chose the technology, the background is as follows. BP has had a presence in Cairo for a long time. It was consolidating facilities into different offices or buildings around the city. It therefore required high-speed links between those sites, a not unusual need where multiple buildings in the same city are involved. Patrick takes up the story: “BP realised that relying on the local telecom provider was going to be not only very expensive, but would not enable them to reach their desired availability and reliability targets for the network. Conversely, ‘owning the infrastructure’ with a wireless solution means that all the equipment is owned and under control of the customer — who can therefore take whatever actions are required to ensure consistent and high uptimes. A local partner responded to an enquiry made by BP locally in Egypt, and suggested our solution as the ‘best fit’ for the customer needs.”

A simple idea Wireless Excellence offers a number of different wireless systems but in this case Patrick was referring to FSO. In principle, the idea is simple: you have a box that generates a laser beam — a very low power light beam — which is modulated. It carries data in the form of ones and zeros from one point to another point. There they are converted back to data.

In practice, however, making this technology reliable has, Patrick said, cost the telecommunications industry as a whole many

80 Oil Review Africa Issue Five 2013

Customers especially like the fact that point-to-point wireless communication using laser is, in most countries, licence-free. millions of dollars and a lot of work. Even when it was commercialised back in the late 1990s companies like Wireless Excellence had to overcome a lack of awareness of FSO (compared to, say, microwave or fibre) with demonstrations and trials.

FSO has many advantages But it has been worth it, and not just for Wireless Excellence. Customers especially like the fact that point-to-point wireless communication using laser is, in most countries, licence-free. In addition, radio spectrum is a limited resource; the microwave spectrum tends to be congested in major cities with hundreds, or even thousands of links all competing for the same frequencies. Infra red, however, is uncongested.

FSO’s other advantages include quick set-up, very high speed (1 Gbps) and low annual fees to Egypt’s NTRA (National Telecom Regulatory

Authority) compared with other wireless technologies. In fact, Patrick explained, “With our reseller we have worked with the NTRA to ensure that all the products and installations meet their needs. The fact that these products use optical (infra-red) rather than RF spectrum means that they are very supportive; these products don't add to the severe and increasing congestion of RF bands, so there is a motivation for all parties to choose optical links where appropriate.”

Its limitations FSO does have its limitations. Transmission is only up to 2km as a rule (though much longer links have been achieved: up to 4km or more) and it requires line of sight transmission. That means, in cities most of all, the transmission and reception equipment is usually rooftop-based. Careful planning is therefore required to ensure that the desired links can be implemented. Also in some cities and regions of outstanding heritage the user may also be at the mercy of planning regulations.

However, most business users, including BP, are fortunate in occupying fairly tall buildings where line of sight is easy to attain, and the units are usually not visible from street level. If a company using FSO doesn't own a building it can usually negotiate with building owners for rooftop access.

Sometimes more height is needed to ensure

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ICT

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line of sight. In such cases small masts can go on top of buildings. In some situations there may even be what Patrick calls “a snooker shot”: pointing a beam at a laser ‘box’ on a different building where a repeater installation redirects it to the one you need to link. The owner of the extra building usually exacts a modest rental for the favour but that is rarely a deterrent to the client.

All links at rooftop level in Cairo What about Cairo? As Patrick said, “It's a busy city!

All our wireless links are up on rooftop level, and mounted in locations where there is clear line of

sight between locations. Our skilled resellers are expert at finding suitable points, starting with maps and then checking by visiting the rooftop sites themselves. It's actually a lot easier than it sounds — and to put it in context globally for the whole industry, there are upwards of a million wireless links a year being installed on similar rooftop sites.”

Nevertheless other factors can be a problem.

For example FSO is also limited by the weather — things like thick fog, heavy snow and in certain conditions extremely heavy sandstorms, although that still makes it viable for much of the Middle East and Africa. As Patrick pointed out, “This

deployment is typical of ones we have done in 65 countries globally. The customer needs, and the solution itself, are as valid and attractive in Cairo as they are in cities as diverse as London, New York, Cape Town, Riyadh, Dubai, Lagos or Baghdad.”

FSO may be an ideal wireless solution to the problem of communicating data in a major city. But is it better than wired approaches such as fibre optics? That’s what we’ll be discussing in the second part of this feature, where we will also look at how the type of communications required by a modern oil company — and even a modern consumer — have changed. ■

Lockheed to provide ARKeX with next generation gradiometres ARKeX HAS ENTERED an exclusive 10-year agreement for Lockheed Martin to provide next-generation full-tensor gravity gradiometers for airborne and offshore geophysical surveying. ARKeX said its multiinstrument agreement will increase existing capacity and forms an integral part of the growth strategy for the company. The eFTGs will improve resolution over the current instrumentation and further enhance geological understanding. The improved resolution will give ARKeX the ability to develop new products and services for the natural resource exploration industry. This will not only allow new resources to be discovered but also reduce exploration timelines and costs.

Gravity gradiometry measures variations in the earth’s gravitational

82 Oil Review Africa Issue Five 2013

field and is a direct measure of the density distribution of the subsurface. The information can help to build a picture of subsurface anomalies, which can then be used by natural resource exploration companies to more accurately target hydrocarbon and mineral deposits.

John Siegfried, ARKeX CEO, commented, “We are really excited about this exclusive agreement. We have been working with Lockheed Martin for a number of years and we have been impressed by their professionalism, responsiveness and approach to pushing the boundaries of this exciting technology. This strategic agreement will not only benefit ARKeX and Lockheed Martin, but the whole exploration industry.”

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Project Databank Compiled by Data Media Systems

OIL, GAS AND PETROCHEMICAL PROJECTS Project YFP - Aje Blk OML 113 Total - OML 99 Ikike Field Total - OML 58 Upgrade Phase 1 Total - Egina Field Development Stubb Creek Field Southern Swamp Associated Gas Solution Project (SSAGS ) Oyo Field Development Owowo Oil Field - OPL 223 Okwok oil field - OML 67 Okoro and Setu Fields Development Ofon Field Development Phase 2 NNPC - Olokola LNG (OKLNG) Plant

Sector Offshore Offshore Oil, Offshore Oil Oil Gas

Facility Offshore Platform Offshore Platform Oil & Gas Field Oil Field Development Oil Field Development Gas Production

Budget 10000000 400000000 1000000000 3100000000 200000000 1000000000

Status EPC FEED EPC EPC EPC EPC

Start Date Q4-2004 Q2-2009 Q1-2006 Q4-2003 Q4-2003 Q1-2011

Completion Date Q1-2015 Q4-2015 Q4-2013 Q4-2017 Q4-2013 Q2-2015

Oil, Offshore Oil Oil Oil, Offshore Offshore Gas

1000000000 250000000 400000000 200000000 500000000 20000000000

EPC EPC EPC EPC EPC EPC ITB

Q1-2006 Q3-2005 Q1-1968 Q3-2006 Q2-2007 Q1-2005

Q4-2014 Q3-2015 Q4-2015 Q4-2013 Q1-2015 Q3-2016

Njaba Oil Field - OML 124 Mart Resources Umusadege Field Development Kita Marine Oil Field - OML 123 FLEX LNG - LNGP1 (Floating LNG Production)

Oil Oil

Oil Field Development Oil Field Development Oil Field Development Oil Field Development Offshore Platform Liquefied Natural Gas (LNG) Oil Field Development Oil & Gas Field

150000000 500000000

EPC ITB EPC

Q1-2008 Q4-2008

Q4-2016 Q4-2014

350000000 500000000

EPC EPC

Q4-2007 Q1-2006

Q4-2015 Q1-2017

FCTA - Karshi Water Supply System Ebok Development Chevron Texaco - Agbami Oil Field Development Chevron Nigeria - Escravos Gas-to-Liquids (GTL) Project Brass LNG - Brass River LNG Plant Afren - OPL 310 Development Afren - OML 115 Development

Water Oil Offshore Gas

Oil Field Development Floating Production and Storage Offloading (FPSO) Desalination Oil Field Development Oil Field Gas to Liquids (GTL)

130000000 450000000 5000000000 1700000000

EPC EPC EPC EPC

Q2-2007 Q1-1998 Q3-2001

Q1-2016 Q4-2013 Q1-2016 Q4-2013

Gas Oil, Offshore Oil

Liquefied Natural Gas (LNG) 3500000000 Oil & Gas Field 200000000 Oil & Gas Field 150000000

EPC ITB EPC EPC

Q4-2004 2009 Q1-2010

Q4-2017 Q3-2014 Q2-2016

Oil Offshore

Project Summary Project Name

TOTAL - Egina Field Development

Status

Engineering & Procurement

Name of Client

TOTAL

Start Date

Q4-2003

Budget ($ US)

3,100,000,000

End Date

Q4-2017

Award Date

Q1-2013

Location

Egina, Nigeria

Facility Type

Oil Field Development

Project Backgrounds Total plans to develop Egina Field in Nigeria.

Project Status IN DECEMBER 2003, Egina-1 was discovered. Egina-2 was discovered in October 2004. In September 2006, an appraisal programme, followed by seismic data processing, resulted in the discovery of well Egina-3 and Egina-4 and Egina-5 the following November.

In January 2013, Samsung Heavy Industries was selected as the preferred bidder for execution of the Egina FPSO facility, and in March it was awarded the EPC contract. In July 2013 the field development plan called for 44 wells connected to a 330m-long floating production, storage and offloading (FPSO) vessel with a storage capacity of 2.3mn barrels, as well as engineering and manufacture of about 76 km of steel tube umbilicals including production,

water injection and (SSIV) umbilicals. That same month Saipem was awarded the EPCI contract for the subsea development of the Egina field. This contract includes engineering, fabrication, and installation of 52 km of oil production and water injection flow lines, 12 flexible jumpers, 20 km of gas export pipelines, 80 km of umbilicals, and mooring and offloading systems.

In August DUCO was awarded the contract to supply umbilicals to the Egina field. Production is expected to start by the end of 2017. In September FMC Technologies was awarded a US$1.2bn contract to supply subsea equipment for the Egina field. The equipment is scheduled for delivery commencing in 2015.

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ICT

ARK CLS launches GeoDataSync ARK CLS, A leading developer of geoscience solutions to the oil & gas industry, has released a powerful new data collaboration technology called GeoDataSync (GDS).

At a time when many seismic interpretation workflows are characterised by multiple geoscience interpretation systems and data storage and duplication challenges, GeoDataSync brings order to the workflow, allowing interpreters to use multiple interpretation systems within the same unified workflow. Data can also be accessed without the need to copy it, removing the need to make copies of large seismic 3D data volumes and dramatically reducing storage costs.

The initial implementation of GeoDataSync, which has been sponsored by a major operator, has been developed as a plug-in to Petrel* seismic to simulation software. Through a separate plug-in, GeoDataSync will also allow users access to 3D seismic data volumes and other data stored within dGB Earth Sciences’ seismic interpretation system, OpendTect.

"Seismic interpretation today is complicated by so many different geoscience software packages and – through the popularity of large 3D seismic cubes – so much data that it’s easy for seismic interpreters to become overwhelmed,” said ARK CLS’s managing director, Adrian Bennetton. “That’s why we believe that GeoDataSync is such an important breakthrough.”

“Running quietly in the background and lightweight, fast and efficient, GeoDataSync unifies the seismic interpretation workflow and enables interpreters to focus on their number one priority – accurately characterizing the subsurface. In a few years’ time, geoscientists will be wondering how they ever coped without GeoDataSync.”

GeoDataSync comes with a number of key features and benefits.

These include: 6 Collaborative working & easy synchronisation between multiple data sources. GeoDataSync ensures easy collaboration, access, copying and synchronisation between multiple data sources and software packages and is ideal for a heterogeneous geoscience software environment. GeoDataSync also works well with smaller datasets, such as interpretative horizons, faults or well data.

6 Improved data management & reduced storage costs. GeoDataSync is simple to install and manage, and provides access to huge 3D seismic data sets without requiring the copying of that data. This removes the need to make copies of large seismic 3D data volumes and dramatically reduces storage costs.

6 Increased asset team productivity. GeoDataSync ensures that all asset team members have access to the right data as and when they need it, increasing team productivity and turning data into high-value information.

6 Leveraging previous investments. GeoDataSync supports data access from legacy systems and can easily access and incorporate historical data into the current interpretation workflow, leveraging previous investments that might have been otherwise forgotten.

6 Easy migration & reduced data corruption risks. GeoDataSync facilitates migration to newer technologies with the minimum of disruption and also significantly reduces the risks of data corruption and data versioning errors.

Depending on customer demand, plans are also being made for further GeoDataSync plug-ins to other mainstream interpretation packages.

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