Oil Review Africa issue 1 2012

ORA 1 2012 Cover_cover.qxd 08/02/2012 16:19 Page 1

■ Geology - p29 ■ Gas - p34 ■ Exploration - p38 ■ Technology - p50

Volume 7 Issue One 2012

www.oilreviewafrica.com

Africa

Covering Oil, Gas and Hydrocarbon Processing

Excellent prospects for Africa’s oil Investment growth in African renewables Drillers return to Namibia

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

Nigeria - first attempt to restructure its oil industry

Managing corrosion: a key challenge Produced water: the billion dollar clean-up African rig count on the rise Improving refinery and process plant operations Oil bunkering - a growing challenge Satellite services: battle of the bands

Martin Trachsel, CEO of SAPETRO See page 74.

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

S01 ORA 1 2012 Start_Layout 1 09/02/2012 12:01 Page 2

...Africa is our home

Block 1

OML 130

ver the past decade, South Atlantic Petroleum has made significant contributions to the development of oil and gas in the Gulf of Guinea. This has been through our participation in the Total-operated Akpo and Egina developments in OML 130 deep offshore Nigeria, as well as the upcoming redevelopment of the SAPETRO-operated Sèmè oil field offshore the Republic of Benin. At the end of 2011 we commenced the acquisition of more than 12,000km of 2-D seismic in our newly acquired concessions - the Juan de Nova Permit and Belo Profond in the Mozambique Channel.

We are continuing to expand our operations across sub-Saharan Africa and we look forward to developing further partnerships.

South Atlantic Petroleum • Nigeria

• Benin • France • Madagascar www.sapetro.com

Juan de Nova (France) & Belo Profond (Madagascar)

S01 ORA 1 2012 Start_Layout 1 09/02/2012 12:01 Page 3

■ Geology - p29 ■ Gas - p34 ■ Exploration - p38 ■ Technology - p50

Contents

Volume 7 Issue One 2012

www.oilreviewafrica.com

Africa

Covering Oil, Gas and Hydrocarbon Processing

Excellent prospects for Africa’s oil Investment growth in African renewables

Columns

Drillers return to Namibia

Industry news and executives’ calendar

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

Nigeria - first attempt to restructure its oil industry

Managing corrosion: a key challenge

4

Produced water: the billion dollar clean-up African rig count on the rise

Analysis

Improving refinery and process plant operations

Excellent prospects for Africa’s oil

10

Oil bunkering - a growing challenge Satellite services: battle of the bands

The IEA has been busy examining the rapid changes in the market for crude oil.

Investment growth in African renewables

12

Investment in renewable power in Africa is set to grow with key sectors being wind, solar and geothermal power.

Martin Trachsel, CEO of SAPETRO See page 74.

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

Oando’s business strategy of diversification and expansion into the upstream oil & gas sector is yielding positive results.

Country Focus Nigeria

16

Editor’s note

The PIB - first at tempt to restructrue the Nigerian oil industry.

Challenging times for NNPC with new oil and gas legislation around the corner.

Interview with SAPETRO’s CEO, Martin T rachsel.

Namibia Drillers return to Namibia as Kudu gas saga rumbles on.

Gas News and developments

34

A round-up of recent gas activity from around the region.

Exploration & Production News and developments

38

A round-up of recent E&P activity from around the region.

Technical Focus Managing corrosion - a key challenge

50

Advanced NDT inspection delivers cost-effective solution for identifying corrosion under pipe supports.

Cathodic protection solutions

66

SUB SAHARAN AFRICA did much better in growth terms than most other regions in 2011 and this should continue for the next couple of years, according to the World Bank. There is also no doubt that the whole of Africa will be playing an increasing role in the supply of oil for the rest of the world.

Africa’s rig count is rising with recent finds offshore both in West and now East Africa, where they have unearthed a succession of huge gas finds. This has also triggered further interest across the rest of the region onshore.

Additionally, investment is growing substantially in renewable energy sources, particularly in wind, solar and geothermal power - a number of African countries are leading the way with national initiatives.

In Nigeria the government is taking action on long-unfulfilled promises to reform the country’s nororiously inefficient and corrupt oil sector, by speeding up the Petroleum Industry Bill aimed at changing everything from fiscal terms to the state oil company.

Elsewhere in this issue we look at how to manage corrosion both onshore and offshore, the restoration of Ogoniland following a recent report, and also the growing challenge in oil bunkering through sabotaged piepelines and offshore attacks.

Cathodic protection solutions for corrosion control and life extension of offshore oil and gas infrastructure.

Produced water

70

54

Legislation regulating its treatment and disposal is making produced wa er a much more serious and expensive problem.

Oil bunkering

62

A growing commercial and security challenge

Africa’s rig count on the rise

68

Exploration in deepwater environments such as West Africa has buoyed demand for rigs able to handle such tough conditions.

Refinery and process plant operations

76

These can be improved with correct application and understanding of plate heat exchangers.

Information Technology VSAT communications

90

The second of three articles on the advantages and disadvantages of the various bands used by both fixed and mobile satellite services.

The semisubmersible drilling rig West Leo from Seadrill has a one-year contract with Tullow of Ghana Ltd.

Managing Editor: Zsa Tebbit - Zsa.Tebbit@alaincharles.com Editorial and Design team: Bob Adams, David Clancy, Andrew Croft, Ian Roullier Prabhu Dev, Immanuel Devadoss, Ranganath GS, Prashanth AP, Genaro Santos, Nicky Valsamakis and Julian Walker

Africa

Covering Oil, Gas and Hydrocarbon Processing

Publisher: Nick Fordham

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Serving the world of business

Oil Review Africa Issue One 2012 3

Industry News & Events

S01 ORA 1 2012 Start_Layout 1 09/02/2012 12:01 Page 4

Executives Calendar 2012 FEBRUARY 13-14 20-23 21-23 21-24

Libya - The Future 3 Nigeria Oil & Gas Africa Energy Indaba NAPE 2012

LONDON ABUJA JOHANNESBURG HOUSTON

www.libya-conference.eventbrite.com www.cwcnog.com www.energyindaba.co.za www.napeexpo.com

IFSEC West Africa Oil & Gas Africa Exhibition & Conference Angola Oil & Gas Libya Oil and Gas Summit 2012 Oil and Gas Communications Ghana Summit 3rd Eastern Africa Oil, Gas & Energy Conference

LAGOS CAPE TOWN LUANDA ROME LONDON ACCRA NAIROBI

www.ifsecwestafrica.com www.fairconsultants.com www.iirangola.com www. libyasummit2012.com www.smi-online.co.uk www.cwc.ghana.com www.petro21.com

SIPS 2012 Nigeria Infrastructure LNG 17 Oil & Gas Libya 2012 MMEC 2012 5th Annual Sub-Saharan Africa Oil & Gas Conference OTC

UTICA LAGOS HOUSTON TRIPOLI MAPUTO HOUSTON HOUSTON

www.geco-expo.com www.cwcnif.com www.lng17.org www.montgomerylibya.com www.mozmec.com energyandcorporateafrica.eventbrite.com www.otcnet.org

Agrikexpo OGAFIC 2012 4th African Gas Conference MOC 2012 5th Nigerian Upstream Conference 3rd East Africa Oil, Gas and Energy Week 2012 13th South African Oil, Gas & Energy

LAGOS ABUJA LONDON ALEXANDRIA LONDON NAIROBI JOHANNESBURG

www.agrikexpo.com www.ogafic.com www.petro21.com www.moc-egypt.com www.petro21.com www.petro21.com www.petro21.com

MARCH 6-7 13-15 20-21 20-21 21-22 27-29 27-28

APRIL 13-15 17-18 16-19 23-26 24-25 26-27 30-3 May

MAY 15-17 22-23 22-23 22-24 24 26-28 29-30

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

Oil and Gas Africa Conference - New opportunities in sub-Sharan Africa WITH AFRICA POISED to be the ‘next oil growth story’, the massive opportunities will fall under the spotlight at the upcoming Oil & Gas Africa Conference, which takes place on 14 March 2012 at the Cape Town International Convention Centre.

The conference programme features a stellar panel of both local and international speakers, all specialists in the oil and gas industry. Conference topics will revolve around the theme, ‘Outlook for sub-Saharan Africa and new opportunities’.

Namibia is attracting the most attention from the oil industry; last year prospectors discovered an estimated 11 bn barrels of oil reserves around the country’s southern coast. More recently, American and Italian exploration companies have found a natural gas deposit equivalent to over four billion barrels of oil off the coast of Mozambique. The southeast African country is now being described as the world’s newest ‘petro-state’.

Over the past 20 years in Africa, new oil field discoveries have increased by over 25 per cent, and gas field discoveries by over 100 per cent.

Adi Karev is fiercely optimistic about the outlook for the oil and gas sector in the region.

Karev is the Global Leader of the Oil & Gas Practice for Deloitte Touche Tohmatsu Limited. “The responsible exploitation of oil could be a game changer for sub-Saharan Africa,” says Karev. “But for this to be a success, there needs to be a significant

4 Oil Review Africa Issue One 2012

and 'mature' buy-in from the region’s governing elite.” Karev is one of the conference speakers and will be addressing delegates on global trends.

Karev points to a number of opportunities to exploit the massive potential, such as joint ventures and partnerships, particularly for South Africa.

“Africa is risky, both geographically and politically, so joint ventures are a way to manage the risks.”

By 2035, China will be responsible for most of the 36 per cent increase in global energy demand, according to the International Energy Agency. This brings opportunities for South Africa. “South Africa can bring execution to projects, most notably from energy giant Sasol. There is also potential for ventures with South Africa’s national oil company, PetroSA,” says Karev.

Anton Botes, Karev’s colleague at Deloittes, supports his views. Addressing delegates at Deloitte’s Energy and Resources Predictions 2012 briefing, he noted that Cape Town has already emerged as a services hub. “There is also potential for other South African ports, as well as Namibia’s Walvis Bay, to more fully exploit the services opportunities that will arise from the ongoing expansion of oil exploration and production activities off the coast of West Africa.

“Oil companies make use of specialist suppliers to provide technology, maintenance, engineering, parts and logistical services,” continued Botes. “We

believe that over the coming five to ten years, there will be tremendous growth in the area of oilfield services as a sub-industry, servicing the huge amount of activity up the west coast of Africa.”

Corrosion damage mechanisms in refineries will be addressed at Oil and Gas Africa. Corroding infrastructure is costing the South African economy around five per cent of GNP. Corrosion costs can be cut by up to 25 per cent if proper inspections are carried out by industries, according to Vanessa Sealy-Fisher, President of the Corrosion Institute of Southern Africa (CorrISA).

The institute is hosting a three-day course that will cover the latest recommended practice for detecting, identifying and preventing in-service damage mechanisms. The course runs alongside the Oil & Gas Africa Expo and Conference. These events take place at the Cape Town International Convention Centre from 13 to15 March 2012.

Cape Town has successfully been developed as a repair and centralised maintenance hub servicing sub-Saharan Africa.

S02 ORA 1 2012 News_Layout 1 09/02/2012 12:05 Page 5

Industry News & Events

S02 ORA 1 2012 News_Layout 1 09/02/2012 12:05 Page 6

Lukoil to spend up to $600mn drilling 3 West Africa wells RUSSIAN OIL MAJOR Lukoil is looking to West African oil fields by investing up to US$900mn in projects in Ghana, Côte d’Ivoire and Sierra Leone. Vice-CEO of Lukoil Leonid Fedun says the West African projects could yield up to six billion barrels of oil and gas.

The company's foreign gas and oil deposits make up around 10 per cent of its assets and it plans to double this number in the next few years. Lukoil expects the West African oil fields to make a great contribution to it. Some experts believe the development could increase Lukoil's production by up to 10 per cent.

Investment in the new projects in Ghana and Sierra Leone has already increased 54 per cent in the first nine months of 2011 and were about $205mn.

Lukoil owns a 56.66 per cent stake in the Cape Three Points Deep Water project in Ghana. Vanco Energy holds a 28.34 per cent stake, Ghana National Petroleum owns 15 per cent.

Recently Lukoil announced a large discovery on the Ivorian shelf, but refused to unveil exactly how much. That project is also a partnership between Lukoil and American Vanco along with Cote D'Ivore's Petroci Holding.

Lukoil has placed its bets on Africa as a promising region for oil production.

Accommodation barges in demand offshore West Africa GLOBESTAR HAS CONTRACTED Springmarine, a joint venture between Exmar and Springview, to supply an accommodation barge for operations in the Gulf of Guinea.

Exmar has also signed a contract with ABC Maritime to bareboat the newbuild Otto 5 accommodation barge for operations off West Africa. Following outfitting, the vessel should start operations in July.

Another Exmar vessel, Nunce, is operating in the region. The Kissama has been idle since last March, but is being marketed for further employment in West Africa.

In December, Exmar was shortlisted for an unspecified mid-term contract to provide an FSO and associated services. The company is hopeful of gaining a contract in the near future.

6 Oil Review Africa Issue One 2012

BP draws up Angola assignments BP HAS AWARDED Oceaneering International a three-year field support vessel services contract offshore Angola.

Oceaneering will provide project management, engineering, and vessel services on blocks 18 and 31, starting February 1. The contract provides for two option periods of one year each, exercisable by BP. Two chartered vessels, the Ocean Intervention III and the Bourbon Oceanteam 101, will be supplied under the contract. Each vessel will be equipped with two Oceaneering work class ROVs capable of working in 3,000 m of water. Ocean Intervention III was mobilised from the Gulf of Mexico to Angola last month.

The contract work scope includes light subsea construction, inspection, maintenance, and repair services on existing and planned subsea infrastructure.

Oceaneering may also provide a third vessel after the commencement date.

BP has also contracted FMC Technologies for manufacture and supply of additional subsea equipment for its deepwater projects off Angola.

FMC will supply four subsea trees, control systems, wellheads, tubing hangers, well jumpers and subsea distribution systems. All equipment will be manufactured at FMC's Kongsberg, Norway, and Dunfermline, Scotland, facilities and should be delivered in 2013.

Final assembly and testing will be performed at FMC’s facility in Angola.

GE Oil & Gas signs compressor supply agreement with Shell GE Oil & Gas has signed an enterprise framework agreement to supply compressors and associated services for Shell’s projects worldwide over the next six years.

Under the agreement, Shell will have access to GE’s most advanced, high-tech compressor technology for deployment in Shell’s key projects in high-growth regions, including Australia, West Africa, Russia and the Caspian region and Canada.

Prady Iyyanki, vice president—turbomachinery, GE Oil & Gas, said, “GE is committed to delivering enhanced value and efficiency to its global customers, including through the delivery of rigorously qualified and validated pre-engineered solutions that equate to faster execution in the pre- and post-order phases. Building on our successful cooperation with Shell over many years across the industry’s most challenging sectors, this agreement will help improve quality and repeatability for Shell, as well as boosting efficiency and optimising production for its mega-projects around the world.”

The GE equipment covered under the compressor enterprise framework agreement with Shell will be manufactured at GE Oil & Gas’ facilities in Florence, Italy, and Le Creusot, France. The agreement includes the supply of centrifugal compressors for the following key market segments: liquefied natural gas (LNG) services, natural gas, refining and petrochemical applications.

GE also has recently announced it will supply two steam turbine-driven compressors for the Shell Prelude Floating Liquefied Natural Gas (FLNG) project offshore Australia—which will be the largest floating offshore facility in the world. To meet the specific project requirements, GE is minimising the casings of the steam turbines and compressors to reduce weight and footprint. GE is designing the compression trains to cover a wide range of operating conditions, developing a technology for potential use in future FLNG plants.

S02 ORA 1 2012 News_Layout 1 09/02/2012 12:05 Page 7

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Industry News & Events

S02 ORA 1 2012 News_Layout 1 09/02/2012 12:05 Page 8

Technip jumps on Jubilee work FRENCH SERVICES PLAYER Technip has been awarded two contracts for Phase 1A of Tullow Oil’s Jubilee project, off Ghana.

The contracts are worth a combined US$130.7mn and cover full project management, engineering, fabrication and installation of a new flexible riser, two rigid flowlines and 11 spools/jumpers as well as the installation of two manifolds and five km of umbilicals.

The contracts will be executed by Technip’s operating centre in Paris and will be supported by its offices in Texas and Ghana, while the risers will be fabricated at the company’s facility in Le Trait, France.

Technip will use its Global 1200 and Deep Pioneer vessels to carry out the offshore installation work which is scheduled to be completed during the second half of the year.

8 Oil Review Africa Issue One 2012

Tullow pioneers African Business Initiative AFRICA'S LARGEST INDEPENDENT oil company, Tullow Oil, has kicked off a new business initiative aimed at attracting and facilitating further investment in the continent.

Invest in Africa aims to encourage long-term investment across the continent to help build and develop local capacity, boost domestic job markets, develop skills and stimulate economic growth.

The programme’s call to action will be supported through a unique partnership with English Premier League football club, Sunderland AFC. As the initial Founding Partner establishing Invest in Africa, Tullow plans to secure five further Founding Partners from the international business community focused on Africa. These Partners will help to evolve and shape the programme in years to come.

Speaking at the launch, Tullow Chief Executive Aidan Heavey said: “Tullow is investing in Africa for the long term and we want more businesses to do the same. Africa has been good to us, and we have been successful, but we want that success to bring growth for local people and economies too. Africa’s a great place to invest and this partnership with Sunderland AFC will allow us to get the message to a global audience.

There are some great opportunities out there and we want other companies who share our vision to join us.”

Ike Duker, Executive Chairman of Tullow Ghana Ltd added: “While we are delighted to be at the forefront of this innovative new programme, this is not just about Tullow. This is an initiative that can help to build stable, investment- friendly environments to allow businesses to grow across Africa, create jobs and enable Africa’s people to share in the wealth and prosperity that come with it.”

S02 ORA 1 2012 News_Layout 1 09/02/2012 12:05 Page 9

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S03 ORA 1 2012 Analysis_Layout 1 09/02/2012 12:42 Page 10

Analysis

The IEA has been busy in Paris recently, examining the rapid changes in the market for crude oil. We put the conclusions of no less than three reports into the context of what else has been going on.

Excellent prospects for

Africa’s oil S

SA DID MUCH better in growth terms than most other regions in 2011, and this should continue both this year and next. So said the World Bank on 18 January. There have been plenty of other glowing reports too, most emphasising the splendid prospects for investment.

However the WB simultaneously warned of falling commodity prices, energy products included, and of the ripple effects of Europe’s continuing currency/debt crises. Crude has been hovering around US$100/bbl for several weeks now, with a good premium for African light grades; it continues to be in high demand in developing Asia; and OPEC is maintaining its policy of compensating for shortfalls. But it decided in December not to ease the supply situation further.

The bottom line is that Africa’s medium-term oil-exports future will probably depend more on higher volumes than on better prices. Several national newcomers to the industry do not have to conform to the restrictive quotas set by the Organization in Vienna; Angolan output will soon be on the way down.

In its December six-monthly review the International Energy Agency commented on tight supply, with emerging markets continuing to outperform their OECD counterparts as consumers. But this organisation was seriously worried about economic prospects too; “One minute to midnight – the clock ticks” it warned. Global demand for oil was expected to have averaged 89.0mn bpd last year, a rise of just 0.7mn bpd on 2010 before reaching 90.3 in 2012.

Due to OPEC including Libya’s major contribution (1.66mn bpd in 2010) supplies have been holding up well.

“Updated medium term projections show global oil demand rising from 88.3mn bpd in 2010 to 95.0 in 2016, growth of 1.1mn bpd per year on average,” said that month’s Oil Market Report. However it revised downwards by 0.3mn bpd the medium-term global demand forecast it had made last June. Just a 1.4 per cent increase in usage is expected this year, less than half what was seen in 2010. All-Africa’s consumption increase (from a tiny base) is accelerating, but the continent will continue to supply the world with massively more oil than it uses for the foreseeable future.

A few weeks earlier the same international agency had issued the 2011 edition of its much-respected World Energy Outlook – just far ahead of the UN’s huge climate change conference in Durban to allow the delegates to absorb the usual hundreds of closely-argued pages about global supply/demand prospects, and their implications for climate change, through 2035.

The [African] continent will continue to supply the world with massively more oil than it uses for the foreseeable future.

An unsustainable energy future “The world is locking itself into an unsustainable energy future,” it said, adding “There is still time to act, but the window of opportunity is closing”.

As usual the IEA again made out its case for a sharp reduction in emissions of greenhouse and other harmful gases, presenting the supply/demand consequences of a range of national energy policy scenarios which all major on the future role of crude oil. It pointed out that it is the transport sector in emerging economies like India and China that will drive future net oil demand growth; Africa’s tiny road, air and fleets that float will make little difference.

10 Oil Review Africa Issue One 2012

African oil continues to be in high demand, especially in developing Asia.

And with regard to the upstream sector it asked “Will investments come fast enough?”, a question that was already being posed in regional energybusiness capitals like Lagos and Luanda, despite the new-found sparkling reputation of sub-Saharan Africa as a magnet for foreign direct investment.

The Agency’s oil market report for January developed these ‘actuals’ (i.e. not forecast) themes, pointing out the likely effect on the oil trades of general deepening of the business downturn in Europe in particular; subsequently the EU placed a ban on supplies from Iran – which show every sign of being taken up elsewhere in Asia anyway.

Since then harsh words have been used at the World Future Energy Summit in Abu Dhabi about the rowing back on fuel subsidies issue in Nigeria; not good for energy security or much else the IEA believes. And the Agency has declared its willingness to release OECD stockpiles of oil – as happened last year – but only in the case of “really serious supply disruptions”, which had certainly not been seen by the end of the month.

A state of major change Add it all up then and it seems that in January 2012 the crude oil market has been going through a state of major change, with demand in the industrialised countries on the way down while in many emerging countries – but very few African ones – it has been racing ahead. OPEC’s share of the global market for oil is expected to reach precisely one half within a few years, rising from just 42 per cent in 2010. More than one African country’s energy officials are currently pondering whether they want to join, given the effect output quotas have had in recent years.

Less than a year ago the International Energy Agency issued a one-off report about the prospects for a “Golden age of gas”. With oil there seems to be less overall certainty about long-term trends, but no doubt at all about an increasing role for Africa – both North and sub-Saharan – in its supply. ■

S03 ORA 1 2012 Analysis_Layout 1 09/02/2012 12:42 Page 11

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S03 ORA 1 2012 Analysis_Layout 1 09/02/2012 12:42 Page 12

Analysis

Investment in renewable power in Africa is set to grow from the 2011 total of $3.6bn in 2010 to $57bn by 2020, a 1,583 per cent increase in nine years. John Daly* reports.

Investment growth in African

renewables A

LTHOUGH AFRICA HAS vast fossil and renewable energy sources, only 20 per cent of its population has direct access to electricity and in some rural areas, four out of five people are completely without power. According to the UN, over 600mn Africans currently do not have access to electric power. A depressing 70 per cent of Sub-Saharan Africa's population is living without access to clean and safe energy for their basic needs such as cooking, lighting and heating, making energy poverty among the most urgent issues facing Africa. Worldwide, more than 1.4bn people worldwide have no access to electricity, and one billion more only have intermittent access.

Over 2.5bn people, almost half of humanity, rely on traditional biomass - wood, coal, charcoal, or animal waste to cook their meals and heat their homes, exposing themselves and their families to smoke and fumes that damage their health and kill nearly two million people a year. More than 95 per cent of these people are either in sub-Saharan Africa or developing Asia.

The good news?

According to the Managing Director of Nigeria's Bank of Industry (BOI), Evelyn Oputu, total investments in renewable energy in Africa rose from US$750mn in 2004 to $3.6bn in 2011. To put this in a global context, worldwide investment in renewable energy has risen from $33bn in 2004 to $211bn in 2011.

And the future?

According to a report issued in August 2011 by Frost & Sullivan entitled "Mega Trends in Africa: A Solar energy from the desert will feed north Africa's increasing energy demands.

12 Oil Review Africa Issue One 2012

bright vision for the growing continent," investment in renewable power in Africa is set to grow from the 2011 total of $3.6bn in 2010 to $57-billion by 2020, a staggering 1,583 per cent increase in nine short years. According to the document, "The key growth sectors will be wind power, solar power, geothermal power and foreign direct investment (FDI) into energy and power infrastructure."

The reason for the spectacular projections?

Africa's combination of a massive unmet demand, including remote communities, allied to an abundance of renewable power potential in the form of solar, wind and geothermal potential. To give but one example, only seven per cent of Africa's hydropower capacity has been developed up to now.

Africa is not yet locked into the inefficient, oftpolluting infrastructure of many Western countries.

Accordingly, Africa with modern efficient technologies could build a renewable energy infrastructure that could bypass the inefficient, fossil fuel-centered energy infrastructure systems of the developed world.

Modest starts in renewable energy have already begun across the continent. Wind power projects in Africa are planned or under way in Egypt, Ethiopia, Kenya, Morocco, Nigeria, Tunisia, and Tanzania including Kenya's 0.3 gigawatt Lake Turkana project and 0.7 gigawatt of capacity under construction in Morocco, while Cameroon, Kenya, Tanzania, and Uganda all have existing biomass power capacity or plans for future development.

Solar? South Africa has its planned solar park in Upington, intended to contribute 5,000 megawatts to the national electrical grid, while North Africa's Desertec is the largest solar power project ever

Lake Turkana Wind Power (LTWP) is planning a 300 MW wind development in Kenya.

conceived, designed at a potential cost of $500bn to provide a significant portion of the electricity needs of participating countries in the Middle East and North Africa (MENA) region and up to 15 per cent of Europe's electricity needs by 2050.

Africa is not yet locked into the inefficient, oft-polluting infrastructure of many Western countries.

UN support Africa's ambitions have the support of the United Nations, where in 2010 the General Assembly unanimously endorsed a resolution designating 2012 as "The International Year of Sustainable Energy for All." UN Secretary-General Ban Ki-moon has set three inter-linked objectives to support the goal of achieving "Sustainable Energy for All" by 2030, which are ensuring universal access to modern energy services, doubling the rate of improvement in energy efficiency and doubling the share of renewable energy in the global energy mix.

The UN Sustainable Energy for All incorporates a number of initiatives focusing on Africa, including World Bank Group's Lighting Africa, the ParisNairobi Climate Initiative, the Africa-European Union Energy Partnership, and the Global Alliance for Clean Cookstoves, as well as the EU's decision to make access to sustainable energy a development priority through its "Agenda for Change." A number of countries, including South Africa, are also leading the way with national initiatives.

But these initiatives are relatively recent and need financial support to prosper. It was only in September 2010 that African and European leaders launched the Africa-EU Renewable Energy Co-

S03 ORA 1 2012 Analysis_Layout 1 09/02/2012 12:42 Page 13

A number of countries are leading the way with national initiatives.

The downside to this picture? Three things - the need for massive amounts of investment capital, a problem attendant to massive amounts of cash corruption, and the continent's changing political landscape, which is already impacting the Desertec North African solar initiative as the Arab Spring rolls the south coast of the Mediterranean.

But both the need and potential are there - all that are currently lacking to make the future predictions a reality are cash and political will. ■

*John Daly OilPrice.com

A question of priorities for South African renewables IT IS DIFFICULT to overstate the significance, both practical and symbolic, of the recent unveiling of the preferred bidders in South Africa’s first 1.4GW renewables tender — for the industry, the country and the continent.

The list of 28 winning projects represents the first step on energy-starved South Africa’s marathon journey to nearly 18GW of new renewables by 2030.

South Africa has long been a tantalising prospect, due to its enormous wind and solar resources, its First World banking and investment sectors, and its huge energy gap.

But for a variety of reasons —from the lack of a local support scheme to more interesting markets elsewhere — most wind and solar companies have not taken South Africa seriously until fairly recently.

“If we were talking three years ago, there wouldn’t have been much attention in this part of the world,” says Peter Brun, head of government relations for Vestas. “There was simply no appetite for higher-risk markets.”

The financial crisis turned that attitude on its head. With the demand for energy stagnating or even declining in much of the Western world, project developers and suppliers are desperate to unearth new markets.

S.Africa offers great opportunity

South Africa is an unusually appetising opportunity. Not only is it an interesting market in its own right, but it represents a beachhead for the continent — a modernised country where renewables companies can set up shop, make a name for themselves, then advance on the rest of sub-Saharan Africa.

“We’re not here just for South Africa,” Brun says. “We’re here for the region.

“We’re having discussions in Namibia, Angola, Ghana, Tanzania and Kenya. Maybe they won’t move at a huge scale, and maybe not tomorrow, but project by project you start to collect an interesting pipeline.”

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Oil Review Africa Issue One 2012 13

Analysis

operation Program (RECP) at the First High-Level Meeting of the Africa-EU Energy Partnership (AEEP) in Vienna.

AEEP's agenda is nothing if not ambitious, as its targets on renewable energy to be reached by 2020 include 10,000 megawatts of hydropower facilities, 5,000 megawatts of wind power capacity, 500 megawatts of solar energy capacity and tripling the capacity of other renewables, such as geothermal, and modern biomass.

S04 ORA 1 2012 Nigeria_Layout 1 09/02/2012 12:39 Page 14

Nigeria

P Harcourt refineries to run at full capacity PORT HARCOURT REFINERIES should begin to work optimally from November after a Turn-Around Maintenance (TAM), the NNPC has assured.

Mr Philip Chukwu, Group Executive Director (GED), Refining and Petrochemicals at the NNPC gave the assurance in Port Harcourt during a recent inspection of the refineries alongside officials of Maire Tecnimont, the contractors which the Federal Government engaged for the TAM. Chukwu, who decried the lack of maintenance of the twin Port Harcourt refineries in the last 12 years, commended the Federal Government for engaging the original constructors of the refineries for the TAM. "Everyone knows that the refineries have not been properly maintained over the years and we have had to manage things. What we are doing now is to have the TAM and complete rehabilitation of the refineries by the original contractors," he said.

The two Port Harcourt refineries which consist of the old refinery with capacity to process 60,000 bpd and 150,000 bpd, respectively, had been functioning at very low capacity with the old one not working at the moment because of lack of maintenance.

Chukwu explained that the 150,000 bpd refinery is expected to be shut down for the TAM on October 1, 2012, by Technimoth Group working in partnership with JGC of Japan, the original builders of the plant, and will reopen in December, 2012, at 90 per cent installed capacity.

He said the TAM and rehabilitation process would also entail overhauling the supply chain and pipelines that bring crude oil and capacity building for staff so as to meet international best practice.

He said the NNPC was also working with all stakeholders, including security operatives, to ensure the pipelines were safe and no longer vandalised.

Mr Tony Ogbuigwe, Managing Director, Port Harcourt Refinery Corporation (PHRC) in his remarks after taking the contractors round the plants, expressed optimism that the refinery would begin to work at 90 per cent capacity by November.

He said preliminary work on the TAM started late in 2010 and the present stage would signal the return to full production by the refineries.

He said that the NNPC had already placed orders for all the necessary equipment for the TAM, noting that the inspection by the management of the construction company would help to fast-track the whole process.

Mr Roberto Bertocco, Managing Director, Maire Tecnimont Group of Italy, said in his remarks that the company which had been on ground in Nigeria for the past 30 years, would be working with the original builders of the refinery.

"I can assure you of a very good job on this project. We have been working with JGC in many parts of the world, so we are also collaborating with them on this project because we have been on ground in Nigeria for the past 30 years," he said.

He expressed optimism that the refinery would be working at full capacity by the end of the year.

The old Port Harcourt refinery was built in 1965 with an initial capacity of 35,000 bpd which was later expanded to 60,000 bpd in 1972. The new wing of the refinery was built in 1989 with a 150,000 b0d capacity to meet local consumption of petroleum products and for export.

Oando denies benefitting from fuel subsidy THE GROUP CHIEF Executive Officer of Oando plc, Mr Wale Tinubu, has explained that oil majors did not unduly benefit from the government's fuel subsidy as they were only paid the differentials between their costs and government approved retail prices. Speaking at the public hearing on the management of subsidy which was organised by an adhoc committee of the House of Representatives, Tinubu said the money paid to marketers as subsidy was not a profit or windfall but under-recovery, arising from the differentials between the landing cost of petroleum products and the official pump price. He stated that the use of the word

14 Oil Review Africa Issue One 2012

'beneficiary' was a misconception as the money was not a special favour from the government but a refund of the actual cost incurred by marketers in the importation of petrol. He said that the marketers spent a average of US$30mn to import 30,000 metric tonnes cargo of petrol, but sold the products at almost $15mn; while the balance was

paid to the marketers as subsidy.

"The Petroleum Support Fund (PSF) expected that there would be underrecovery. For example, when the landing cost is less than the pump price, we pay back to the government. For example, during the Yar 'Adua administration, when the petrol price was N65 and the crude oil price dropped to $50 per barrel, the marketers paid back the fund. I remember that Oando paid back N1bn to the Federal Government," Tinubu said. He noted that when the subsidy regime was introduced in 2006, three major marketers participated in the scheme Oando, NIPCO and NNPC.

Pacific newbuild gets to work T H E PA C I F I C S C I R O C C O deepwater drillship has started work under a contract with Total off Nigeria, according to its parent company.

Pacific Drilling's newbuild, capable of drilling to 11,278 m feet in up to 3,658 m of water, began its work on 31 December, the company said.

It has a one-year contract with Total's local subsidiary at a dayrate of US$470,000, with options for up to four more years.

The ship was delivered from Samsung Heavy Industries’ Geoje facility last year.

Pacific Scirocco deepwater drillship.

S04 ORA 1 2012 Nigeria_Layout 1 09/02/2012 12:40 Page 15

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S04 ORA 1 2012 Nigeria_Layout 1 09/02/2012 12:40 Page 16

Nigeria

A week of protests in January that brought all economic activity to a halt, has jolted the Nigerian government into taking action on long-unfulfilled promises to reform the country’s notoriously inefficient and corrupt oil sector. Jon Offei-Ansah reports.

The PIB - first attempt to restructure the

Nigerian oil industry A

LTHOUGH THE IMMEDIATE cause of the protests was the removal of fuel subsidies, the protest leaders said the underlying angst was about the corruption and mismanagement on the country’s massive oil wealth. This has prompted President Goodluck Jonathan and his oil minister Diezani Allison-Madueke to initiate a number of actions on the long-delayed reforms to the oil sector.

Allison-Madueke promised to investigate corruption in the sector and ordered the country’s corruption watchdog to investigate the subsidy system, sending agents to the state oil company and petroleum pricing regulator. The Senate has also opened a probe into the fuel subsidy system while the oil ministry set up a committee designed to facilitate passing of a crucial oil bill. In midJanuary, the government ordered a fresh audit of its entire oil and gas sector covering the last three years, a move viewed by some observers with scepticism given that previous such audits have usually not been acted on. ‘This is the best outcome of this whole saga. If they bring in the long promised changes to the Nigerian National Petroleum Corporation and others it will be the best thing that happens,’ Stephen Eze, a lawyer involved with the oil industry, was quoted by the local press as saying. ‘People are asking serious questions and government is on its toes.’

Too little, too late?

Nigeria's oil sector has long been criticised for lacking transparency and for mismanagement, including in a report compiled by international accounting firm KPMG. Allison-Madueke pledged to review such reports, but some analysts questioned her ministry's good faith in doing so now. ‘The KPMG report has been on your desk for over a year. So why now?’ asked Kayode Akindele, partner at Lagos-based financial advisory firm 46 Parallels, suggesting this may be too little, too late.

Despite being among the world's top 10 oil producers, Nigeria relies heavily on imported fuel as its own refineries are dilapidated, so the subsidy has become a cash handout of billions of dollars to a cartel of wealthy fuel importers.

Investment on refining and developing further oilfields for production hinges on passing a wideranging Petroleum Industry Bill (PIB) that has been stuck in parliament for more than four years, costing Nigeria billions of dollars in lost investment. Crude oil exports account for 80 per cent of government revenue and 95 per cent of

16 Oil Review Africa Issue One 2012

Total has found a new oil field off the coast of Nigeria.

Allison-Madueke promised to try to speed up this massive bill aimed at changing everything from fiscal terms to the state oil company. foreign currency earnings. Allison-Madueke also promised to meet legislators to try to speed up this massive bill aimed at changing everything from fiscal terms to the state oil company, before setting up the committee to do so. “The set up of a bipartisan Special PIB Task Force is probably one of the positive outcomes of the recent events in Nigeria,” said Samir Gadio at Standard Bank.

"My feeling is that there is now the right momentum to speed up the adoption of the longdelayed bill, although the risk of public policy inertia will remain a concern," he added.

Another factor that protests brought to light is anger over the huge cost of government, particularly in the national assembly, where pay and perks are among the world's highest. That could also help nudge the PIB along.

The bill, conceived by former petroleum minister, Alhaji Rilwan Lukman, has pitched the Nigerian government and foreign oil companies against each other, with foreign oil multinationals appearing to be having the upper hand with the active support of their home governments. Already, the National Assembly appeared to have dumped the bill, with investments in the sector on hold and existing investments largely unsure as the multinationals are up in arms against what they see as a potential breach of contracts. Last year, a British openly warned against the adjustment of the existing contracts on account of the proposed bill, noting that, “while the oil bill is good, a contract is a contract that must be respected by all parties.”

It was specifically learnt that several foreign heads of governments had contacted the Presidency directly over the Bill while Western embassies in Abuja were said to be neck-deep in the lobbying to considerably water down the bill. A source within the administration even hinted that both Prime Minister David Cameroon of the United Kingdom and Chancellor Angela Merkel of Germany who visited President Goodluck Jonathan in 2011 dropped words in favour of a reviewed version of the bill favourable to the International Oil Companies (IOC).

S04 ORA 1 2012 Nigeria_Layout 1 09/02/2012 12:40 Page 17

The aims of the bill

Few could argue convincingly against the many opportunities the Bill would bring.

A new chapter For Africa’s most populous country, the proposed petroleum legislation signals a new chapter in a highly troubled industry. While many would agree that further revisions to the Bill are required in order to address concerns such as clearly defined areas of responsibility for the new regulatory agencies, the deregulation of petroleum product prices and issues relating to unintended consequences, for example reduced exploration and

Nigeria

The bill had sought to wrest control of the oil sector from the foreign oil companies and ensure greater accountability, transparency and anticorruption in the collection, determination, recording and management of the nation`s multibillion dollar oil revenue. The oil companies, made up largely of Shell, ExxonMobil, Chevron, Texaco and Total, were opposed to many provisions of the bill which increased royalties payable to the Nigerian government, among other things. The oil companies were also said to be opposed to provisions in the bill which stipulated determination of crude outputs at the points of production rather than at export points which is the current practice.

It was learnt that the provision that 10 per cent of oil earnings should go to the oil producing communities was seen by the oil companies as an extra burden on their investment which they warned would lead to disinvestment in the Nigerian oil sector.

First oil from Chevron’s Agbami Field, in water depths of 1,400m, was achieved in July 2008.

production activities from IOCs as a result of fiscal disadvantages, few could argue convincingly against the many opportunities the Bill would bring.

The local content aspects of the reforms, for example, would enhance indigenous involvement in the industry. In addition to the compulsory participation of Nigerians in both the exploration and the production side of the petroleum industry, training will be made available to Nigerians, which will encompass all areas of petroleum industries, thus guaranteeing that the country as a whole and local communities benefit from such operations by having access to gainful employment and education opportunities.

Companies that hold petroleum mining leases will be obliged to ensure no less than 95 per cent of the managerial grades carrying out these functions are occupied by Nigerians. In addition to a more robust system of environmental regulation, which would introduce reporting obligations on operations throughout the oil and gas cycle, the abolition of discretionary awards should improve transparency and make the procedure for the award of licences clearer.

Meanwhile, an international group named Facility for Oil Sector Transparency in Nigeria (FOSTER) has issued a policy brief, urging the Jonathan-led administration to ensure quick passage of the bill. The group listed six main provisions of the bill which the administration must protect, if the nation is to make any progress in the struggle for accountability, transparency, increased national benefit and anticorruption in the nation’s oil sector.

The provisions include open, competitive and transparent oil block award process, strong rules for lifting oil licenses, defining process for selling shares in the NNPC and Joint Ventures Operations, increased access to oil transaction information, clarity on revenue flow and better NNPC oversight and corporate government.

The PIB is the first attempt to restructure the Nigerian oil industry to enforce sustainability, transparency and greater Nigerian control over her natural resources. Many are hopeful that the PIB will achieve all of its aims and live up to the view that it proposes a better regime than the one currently in place. ■

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S05 ORA 1 2012 NNPC_Layout 1 09/02/2012 12:37 Page 18

Nigeria

With new oil and gas legislation around the corner, these are challenging times for Nigeria’s state oil company.

NNPC

on the move T

HESE ARE CHALLENGING times for the Nigeria National Petroleum Corporation (NNPC).

And with the government hopeful of passing the much-delayed Petroleum Industry Bill this year, 2012 could be a particularly eventful time for Nigeria’s long-established state oil concern.

A vast piece of legislation, the Bill is aimed at changing everything from the industry’s fiscal terms to a complete overhaul of the national oil champion itself.

At its core, this includes the broad commercialisation of NNPC, in a bid to make the company more efficient, more profitable and more competitive.

Longer term, the aim is to transform NNPC into a major international player.

This will address how the state entity is funded - which has long been an issue with regard to how NNPC finances its share of upstream operations its structure and organisation, where revenues will go, among many other things.

It also means tackling deep-rooted mismanagement and corruption issues at the company, which operates in all corners of the energy sector, from upstream production through to refining and transport.

Longer term, the aim is to transform NNPC into a major international player, along the lines of other successful national oil companies such as Brazil’s Petrobras or Norway’s Statoil.

These model companies have forged hugely successful international businesses through the years.

Ripple effect There is clearly a long way to go but there are already big changes rippling through Nigeria’s oil and gas industry, with the emergence of small indigenous companies, and increasing local content more evident.

Multinationals such as Shell and Total still dominate, though they are relinquishing more and more ground to aspiring Nigerian hopefuls.

The intention is to create a more sustainable oil and gas industry, and one that will benefit more and more Nigerians.

NNPC manages the government's main oil producing joint ventures with both Shell, Total and other foreign partners, namely ExxonMobil, Chevron and Eni. These joint ventures still account for more than 90 per cent of Nigeria's crude oil production.

This is big business and NNPC’s core activity.

The company’s earnings soared to US$16.79bn for the period January-October 2011, beating the group’s full year target of $13.9bn.

NNPC chief executive Austin Oniwon attributed the success to higher oil prices.

He also confirmed that oil production had stabilised at around 2.4mn bpd, after a series of production shut ins following a rise in domestic unrest in recent years.

With oil accounting for about 80 per cent of state revenue and more than 95 per cent of export income, this strategic upstream position makes any changes at NNPC fundamental to how the industry works overall.

Investment hopes

NNPC Chief Executive, Austin Oniwon.

18 Oil Review Africa Issue One 2012

There are hopes that the passing of the new Bill may foster a more conducive environment for drilling and investment.

Oniwon said that NNPC would require annual investment of $13.9bn over the next five years to meet its production target of three million bpd of crude over the next 10 years.

While Nigeria had largely been able to sustain production levels it has not been able to add to its output or reserves due to funding constraints.

With unrest in the Niger Delta, coupled with the uncertain legislative backdrop, energy investment

in Nigeria has waned for some time.

The managing director of Total's Nigerian subsidiary, Guy Maurice, told Platts back in November that drilling had hit an all time low in Nigeria and that the country needed to provide a more enabling environment for companies to step up exploration.

Movement on some long-stalled projects There is movement on some long-stalled projects though including the proposed Brass liquefied natural gas (LNG) plant.

NNPC last year signed a $2bn soft loan from a consortium of Japanese companies led by the Japan Bank for International Co-operation to fund its large equity share in the liquefaction terminal.

NNPC will also dilute its 49 per cent equity holding in Brass LNG to 30 per cent, in line with a government directive, and has offered small stakes to LNG Japan (4 per cent), Itochu (3 per cent) and Sahara/Sempra (2 per cent).

Other shareholders include multinational energy companies Eni, ConocoPhillips and Total.

NNPC expects a final investment decision on the project early this year which, if it were to go ahead and become the nation’s second LNG export plant after the Nigerian LNG complex on Bonny Island would provide some very welcome relief.

It would also be a huge achievement in monetising some of the nation’s vast gas deposits.

Nigeria is keen to shift its emphasis on to gas to diversify its revenue streams, a strategy in which NNPC will play a critical role.

Farewell subsidies One immediate challenge in 2012 for the company is the government’s push to end fuel subsidies.

NNPC buys refined petrol at international prices and sells it on to local marketeers at a big discount because Nigerians see cheap petrol as their birthright.

Although Nigeria is a major oil producer, it

S05 ORA 1 2012 NNPC_Layout 1 09/02/2012 12:37 Page 19

S05 ORA 1 2012 NNPC_Layout 1 09/02/2012 12:37 Page 20

Nigeria’s refineries are insufficient and dilapidated.

Nigeria

the West African nation to import much of its fuel.

The move to abolish the subsidy is key to reforms needed for an upgrade of Nigeria’s credit rating, which ultimately would enhance investment prospects.

Future look

must import almost all the petroleum products it needs because its own refineries are insufficient and dilapidated.

Nigeria must import almost all the petroleum products it needs because its own refineries are insufficient and dilapidated.

20 Oil Review Africa Issue One 2012

President Goodluck Jonathan has pledged to use savings from the estimated 1.2 trillion naira ($7.4 billion) subsidy to invest in power plants, roads and other infrastructure.

But the moves have proved unpopular with unions and consumers, prompting angry protests and strikes.

Gasoline prices in Nigeria more than doubled after the president abolished the subsidy.

The price had been capped at 65 naira a liter, undermining investment in refineries that forced

But there is still much work to be done yet in preparing NNPC for the demands it faces.

Indeed, the fortunes of national oil companies tend to mirror resource-dependent countries’ economic performance, a fact that does not bode well for NNPC. While Petrobras and Statoil have flowered, their respective national economies, Brazil and Norway, have prospered, much like Malaysia’s state oil firm Petronas.

The same cannot be said for Nigeria, however.

With exploration drilling in the doldrums, the investment outlook still cloudy and ongoing militant unrest in parts of the country, change cannot come soon enough for NNPC and its affiliates. The same goes for Nigeria too.

And this year, that will start with the introduction of the new petroleum legislation, a milestone in the long term transformation of NNPC. ■

S05 ORA 1 2012 NNPC_Layout 1 09/02/2012 12:37 Page 21

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Nigeria

S05 ORA 1 2012 NNPC_Layout 1 09/02/2012 12:37 Page 22

Mini diesel refinery receives LTO

Camac makes moves as Eni divests in Nigeria

NIGERIAN AUTHORITIES HAVE granted a license to operate (LTO) to the Niger Delta Exploration and Production (NDEP) Plc, in respect of the Ogbele topping plant, a mini refinery located on the Ogbele field in Eastern Nigeria.

The topping plant has the capacity to produce 120,000 litres of diesel from 1,000 barrels of crude oil from the Ogbele field every day. This means, that for every ten days, it can produce 1.2mn litres of diesel, and for every month, can deliver 3.6mn litres into the Nigerian market.

"This licence, the first of its kind to be granted to an independent, publiclyowned Nigerian company, gives NDPR full authority to operate its mini diesel refinery (topping plant) at the Obbele Field in old OML54" according to CEO of NDEP, Layiwola Fatona.

"The LTO will make NDEP's mini diesel refinery the first of such independently-owned and fully operational diesel refineries in Nigeria. The diesel has been certified by the Department of Petroleum Resources (DPR) as meeting all the quality controls and specifications, " Fatona explained.

"The mini refinery was installed to initially promote self-sufficiency in NDEP's operations and now the LTO has been granted, NDEP will be able to contribute to Nigeria's energy production by selling surplus diesel on to independent marketers, for local consumption. The refinery will therefore not only benefit NDPR's operations, but will also boost local capacity and local content."

Fatona describes the building of the plant, as well as the government's granting of the LTO, as "a precedent". This is a ground-breaking achievement.

With four government refineries delivering sub-optimal performance, Nigeria has struggled with the prospect of private sector ownership and running of refineries. Small as it is, this is the only privately owned legitimate hydrocarbon refinery in the country.

ENI IS SELLING a large chunk in two offshore Nigerian blocks to a company related to US independent Camac Energy which also revealed a raft of new deals.

Houston-based Camac is also acquiring a trio of offshore licences in West Africa and revealed details of its purchase of private outfit Avana Petroleum in an all-shares deal.

Camac reported that it has been informed by Nigerian Agip Exploration, an Eni subsidiary, that it is divesting its entire 40 per cent stake in licences 120 and 121 in which it is currently partnered by Camac.

The holding is going to Allied Energy, which itself is an affiliate of Camac’s largest shareholder, with closing of the transaction expected in the first quarter next year.

Allied is expected to ramp up exploration at the licences and is also planning to drill two additional wells on the Oyo field beginning from next year.

“These two wells are expected to significantly increase oil production over current levels,” Camac wrote.

On top of this, Camac revealed that it has reached a deal with two unidentified national oil companies to acquire three exploration licences in three blocks off West Africa. Camac did not identify the blocks but said it will be the operator with a majority stake.

The blocks are in the “highly prospective” West African Transform Margin where there have been recent discoveries in Ghana and Sierra Leone.

Signing of production sharing contract is expected in the first quarter of 2012.

Camac confirmed it is buying Isle of Man-registered company Avana for the equivalent of US$15mn in an all-shares deal. The deal is split into three tranches with $10mn worth of shares swapping hands in the first tranches and $2.5 mn worth in the next two tranches.

Mart Resources to increase production

African Order of Merit for SGS

NIGERIAN AGIP OIL The Niger Delta. company has agreed to increase the combined export capacity for all the marginal fields in "The Cluster", in the north west central Niger Delta by 10,000 bopd, bringing the total export capacity from its current level of 11,000 bopd to 21,000 bopd. The fields include Platform Petroleum-operated Egbeoma Field, Energia Resourcesoperated Obudugwa/Obodeti Field and Mart Resources-operated Umusadege Field.

The additional export capacity, which is expected to be implemented in several phases over the next four months, will be allocated among the Cluster members on a pro-rata basis based upon the production capacity of the fields in the Cluster and other factors.

The first phase of the export capacity increase, which was implemented in the last week of December 2011, has resulted in Cluster export capacity increasing by approximately 4,000 bopd to 15,000 bopd.

Since the implementation of the export capacity increase, a majority of increased cluster export capacity has been allocated to the Mart Resources-operated Umusadege Field. Mart and its co-venturers anticipate that the Umusadege Field will contune to be allocated a majority of the total export capacity available to the Cluster once it is fully implemented.

SGS IN NIGERIA has received the African Order of Merit in Testing and Pipeline Welding Inspection 2011 from the Institute for Government Research and Leadership Technology in recognition of SGS’s outstanding work and excellent service delivery on June 25, 2011. SGS was presented with the award during a prestigious ceremony in the Nicon Luxury Hotel in Abuja, Nigeria.

As an independent third-party company, SGS was selected from among many companies as the winner of the African Order of Merit in testing and pipeline welding inspection 2011 by the Institute for Government Research and Leadership Technology, a registered project initiative of the African Foundation approved by Nigeria’s Federal Ministry of Education.

The African Order of Merit is an esteemed recognition of companies which deliver particularly excellent services in a variety of sectors, and thus contribute to the development of the Nigerian economy.

SGS is proud to be honoured with this significant order, which acknowledges SGS’s excellence in testing and pipeline welding inspection. With its first-rate experience and competence, SGS is looking forward to even more challenging projects through which it can support the Nigerian government in boosting their economy.

22 Oil Review Africa Issue One 2012

SGS conducts long range ultrasonic testing to minimise the risk of shut-downs.

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Nigeria

Afren lining up further field developments offshore Nigeria AFREN HAS COMPLETED the initial phases of the shallow-water Ebok field development off Nigeria, following commissioning and ramp-up of all 14 production wells.

The jackup Transocean High Island Vll remains at the field’s west fault block area. Afren and partner Oriental Energy Resources plan to drill up to four further horizontal production wells from this

Transocean’s High Island VII jackup rig, Niger Delta.

location, targeting oil-bearing reservoir zones not drilled during the initial phases of field development work.

They are also lining up exploration wells on a 35mn bbl prospect on the untested Ebok north fault block during the first half of 2012, and on the 60mn bbl Ufon prospect in the OML 115 lease.

In November, Afren completed a fourmonth plus ocean bottom cable 3D seismic survey over the whole Ebok/Okwok/OML 115 area which involved acquiring 348 sq km of data.

Processing should be complete by April.

The results should assist development planning for the 51.8mn bbl Okwok field ahead of formal submission of a field development plan to the Nigerian authorities.

At this stage, the most likely scenario

is installation of a dedicated production processing platform tied back to the existing 1.2mn bbl Ebok FPSO 13 km to the west.

Afren is also looking to farm-out part of its interest in OPL 310 which extends from the shallow water continental shelf to deepwater offshore southwest Nigeria, and covers an underexplored basin with a proven working hydrocarbon system.

Several promising structures have been identified in the same Senonian, Turonian, and Albian sandstone intervals that have yielded major discoveries along the Ghanaian and Côte d’Ivoire sections of the West African Transform Margin.

In Nigeria - São Tomé & Príncipe JDZ block 1, where Afren has a 4.41 per cent interest, new operator Total has proposed drilling this year an appraisal well on the Obo discovery and one exploration well. The first well should spud in this quarter.

Chevron plans relief wells to control Funiwa Deep 1A well CHEVRON NIGERIA LTD (CNL) is finalising plans to begin drilling two relief wells to control the Funiwa Deep 1A well. The fire is still burning at the well, but at a diminished rate. Based on the condition of the well, the safest way to control the well is to drill a relief well to kill the well at reservoir depth.

CNL is mobilising two rigs and planning to drill two relief wells. The rigs are being provided by Transocean, on loan from ExxonMobil, and Noble, in co-operation with ENI and the Nigerian National Petroleum Corporation.

CNL continues to monitor the well for impacts to the environment. CNL has hired local community residents as beach walkers to monitor the shoreline. To date there have been no reports of crude oil on the beaches.

A fire started aboard the shallow-water jack-up drilling rig KS Endeavor. Contracted by Chevron Nigeria Limited (CNL) and operated by FODE Drilling Nigeria Limited, the rig was drilling a natural gas exploration well approximately 10 km off the coast of Nigeria and in roughly 12 m of water.

The cause of the incident remains under investigation. CNL is fully co-operating with all relevant Nigerian government authorities. The company affirms its commitment to operational excellence, the safety of its personnel, the security of its assets and protection of the environment.

Nigeria orders audit of oil & gas sector NIGERIA’S GOVERNMENT ORDERED a fresh audit of its entire oil and gas sector covering the last three years, the latest move to clean up corruption in Africa's biggest oil industry after a week of antigovernment protests, according to a report.

The move follows the opening of an investigation into the sector by the corruption watchdog and a separate Senate investigation into fuel subsidies.

"As part of government's anti-corruption agenda, council today ... approved the award of contracts to two audit firms to conduct a thorough audit of the accounts and activities of all government institutions and entities in the oil and gas industry from 2009 to 2011 with nine months completion period," Reuters quoted information minister Labaran Maku as saying.

President Goodluck Jonathan has come

24 Oil Review Africa Issue One 2012

under intense pressure to clean up Nigeria's two million bpd oil sector, after a week of protests over fuel prices revealed public anger about corruption and waste of the country's oil wealth.

Unions called off a week-long strike, after Jonathan partly backed down on the scrapping of a popular fuel subsidy. He and oil minister Diezani Allison-Madueke promised prompt action to implement delayed reforms to the oil sector.

Maku named two Nigerian firms at the auditors: Haruna, Yahaya & Co and Sada, Idris & Co. "The audit would be carried out in all government revenue-generating ... institutions and entities in the oil and gas and solid minerals sectors of the country," he said. "The audit firms shall access production, exports, imports and

unaccounted oil and gas ... and other relevant streams."

Last month, Nigeria's corruption watchdog on orders from Allison-Madueke launched an investigation into the subsidy system, sending agents to the state oil company and petroleum pricing regulator.

On the same day, her ministry announced that it had set up a committee designed to facilitate the passing of an oil bill meant to overhaul the entire sector.

Sceptics will point out that the Nigerian government has invited auditors into its oil and gas sector before – and failed to act on their reports.

A report compiled by international accounting firm KPMG into the opaque state oil company has been on the oil minister's desk for a year, but no action has been taken on it yet.

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S06 ORA 1 2012 Namibia_Layout 1 09/02/2012 12:34 Page 26

Namibia

Drillers return to Namibia as Kudu gas saga rumbles on.

Namibia back

in sight F

INALLY, AFTER YEARS lagging behind other African exploration bright spots, things seem to be picking up for Namibia’s upstream sector.

Perhaps it is the limited availability of richer pickings elsewhere in West Africa - the country sits just south of high flying Angola - or possibly the dramatic emergence of offshore eastern Africa that has reignited the imagination of drillers.

But one thing is for sure: there is gas offshore Namibia and plenty of it.

Now, drillers are looking to add oil to the list, as well as bump up more gas reserves.

Kudu gas The Kudu gas field, first discovered in 1974, holds proven gas reserves of 1.3 trillion cubic feet (tcf) though estimates suggest actual numbers could be much higher, between 3-9 tcf.

The difficulty in pinning down this figure highlights the fraught history of the Kudu deposit, which has through the years been held by the likes of Shell and Chevron.

The asset - located in Production Licence 003, some 170 km offshore Namibia’s south-west coast is currently owned by a group comprising Tullow Oil, Itochu, state-owned Namcor and Russian gas giant Gazprom.

The trouble is, after nearly four decades, no one has yet found a way to make it pay.

Numerous development scenarios have been played out on the drawing board - from floating liquefied natural gas (LNG) platforms, to onshore gas and power projects - but none yet compelling enough to attract real investment dollars.

Consequently, Kudu’s gas pool stays exactly where it has done for the millions of years before it was

Chariot’s operations offshore Namibia.

26 Oil Review Africa Issue One 2012

One thing is for sure, there is plenty of gas offshore.

discovered, deep beneath the ground.

That said, current operator Tullow remains hopeful. It recently agreed a new deal for the field area, taking on a 25-year Production Licence with an optional 10-year extension, suggesting it thinks monetisation is a true possibility.

There is hope that development decisions could even be taken this year.

Drillers return One of the stumbling blocks has been the relative remoteness of the field, away from major consumer markets, plus its size - large enough to be of great interest, but not sufficient at present to justify a standalone gas export project.

Crucially, no Kudu upstream operator has been able to prove up the higher gas reserve estimates that could make a crucial difference, at least so far.

Things are changing in Namibia, however, with renewed interest from other explorers, a turn of events that might just have a bearing on Kudu itself.

If new drilling can yield positive results elsewhere in the country it might just build the critical mass to make Kudu fly once and for all, so the theory goes.

This could mean oil as well as gas, according to aspirants now gearing up to drill.

The upstream arm of oil trader Arcadia Petroleum is looking to spud its first well in Licence 0010 this year, possibly around the middle of the year, subject to funding and rig slots.

Three structures in the area, Alpha, Gamma and Delta, collectively have the potential to contain up to 10bn barrels of recoverable reserves, it says.

If just a fraction of this potential is proved by the drill bit then it could be a game changer for Namibia’s nascent offshore industry.

Things are changing in Namibia with renewed interest from other explorers.

Arcadia is joined in its search by UK-listed Tower Resources, which also holds an interest in two other Namibian blocks.

Juniors jump in There are plenty of other junior E&P hopefuls ready to test the waters too, including UK-listed Chariot Oil & Gas, which has an interest in eight offshore blocks.

It hoped to drill the Tapir South prospect, located in Northern Block 1811 A offshore, by the end of 2011, but had to put back plans after it failed to secure a rig slot.

The site is drill ready - all long lead items have been delivered, all service contracts signed, the support base secured and the drill permit granted and it now hopes to spud during the second quarter of this year, the first of up to 4-5 wells through to end-2013.

Chariot’s CEO Paul Welch has called 2012 a “pivotal year” for the company with an exploration well planned in each of its northern (in the Namibe Basin, north of the Walvis Ridge) and southern (straddling the Luderitz/Walvis basins) Namibian blocks, plus the results of a 3D seismic due in on its central blocks (in the Orange basin).

In the southern blocks, Chariot has been successful in bringing in heavyweight partners BP and Petrobras for support, a further indication of the country’s potential.

Australia’s Pancontinental is equally bullish about its prospects offshore block EL 0037, in Walvis Bay, northern Namibia.

The company operates the concession, with minority partner Paragon Investment, and is currently gearing up for seismic work.

Serica Energy is another UK-listed player with significant exposure to Namibia, recently signing up four blocks in the Luderitz basin: 2512A, 2513A, 2513B and 2612A Starting with new 3D seismic, the company will also work up existing 2D data, with a view to drilling a first well in the third or fourth year of a four-year initial contract term.

S06 ORA 1 2012 Namibia_Layout 1 09/02/2012 12:34 Page 27

S06 ORA 1 2012 Namibia_Layout 1 09/02/2012 12:34 Page 28

Namibia

Niche potential And there are other opportunities besides Namibia’s clear offshore potential.

In October, US junior Frontier Resources International landed two onshore blocks (1717 and 1817) in northern Namibia, its first step into the country.

The blocks cover some 18,900 sq km of largely unexplored territory in the Owambo basin, near the border with Angola.

Other companies operating onshore include Houston-based Hydrocarb/ATA and local company Preview Energy.

The list also includes companies keen to assess Namibia’s unconventional assets too, such as Toronto-listed junior Eco (Atlantic) Oil & Gas. In early December, it farmed out stakes in four of its coalbed methane blocks in Namibia to privately owned West Bay Investments.

Within a few weeks, it had farmed out equity in its offshore blocks as well to Azimuth Ltd, an exploration and production company jointly owned by Seacrest Capital and Petroleum Geo-Services.

Azimuth nets a 20 per cent working interest in each of Eco Atlantic’s offshore Namibia licenses - the Cooper License (Block 2012A), the Sharon License (Blocks 2213A & 2213B) and the Guy License (Blocks 2111B & 2211A) - in return for funding 40 per cent of the cost of 3D seismic work across all three areas.

Azimuth managing director Aaron D’Este recently described Namibia as “an exciting and promising petroleum province”.

The present flurry of upstream activity could potentially transform the outlook for Namibia.

28 Oil Review Africa Issue One 2012

Hopefully new drilling can yield positive results.

Big year ahead The present flurry of upstream activity could potentially transform the outlook for Namibia, which sits so tantalisingly close to oil-rich Angola.

It could also provide the much-needed lift for Namibia’s long known gas field, Kudu.

The Kudu partners may finalise development plans anyway this year, with a view to bringing the field into production by around 2015/16.

The current intention is to build a gas pipeline that will connect Kudu to an 800 megawatts (MW) power station in Walvis Bay. This gas will be used both in Namibia, helping to meet the country’s growing energy demand and for export.

The state electricity company Nampower continues to seek commercial agreements with fellow power utilities Zesco of Zambia and Eskom of South Africa, though these talks have trundled on for years.

But with all the drilling planned, and with the possibility of movement on Kudu, it will surely be an important year for Namibia one way or another. ■

S07 ORA 1 2012 Geology_Layout 1 09/02/2012 12:31 Page 29

TGS to begin 3D survey off Angola

CIRCLE OIL HAS announced the successful completion of the 2D and 3D seismic acquisition program in the Lalla Mimouna and Sebou permits in the Rharb Basin, Morocco.

A total of 154 sq km of 3D seismic data with a 12.5 m bin size were acquired. In addition, 22 line km of 2D seismic data were acquired in the Sebou block. The data was acquired by Prospectuini SA. Acquisition parameters and shooting techniques were similar to those which were employed very effectively in the previous 2D/3D survey, completed in the Sebou permit in 2007/2008, which generated the targets for the highly successful drilling programmes undertaken in 2008/09 and 2010/11, during which 10 successful wells were drilled.

Processing of the acquired data has now commenced and preliminary results indicate the presence of both expected and a number of additional potential targets for drilling, subject to further interpretation, in the forthcoming drilling campaigns in the Rharb permits. The interpretation of the data is expected to be completed by the end of the first half of 2012.

Prof C D Green, CEO, said, "The successful completion of the Lalla Mimouna and Sebou seismic survey acquisition, together with the recent completion of the construction of new infrastructure maintains our momentum in the Rharb Basin. We will make further announcements on the prospects once the data has been fully processed and interpreted."

NORWEGIAN GEOSCIENCE DATA services firm TGS is set to begin a 3D multi-client survey covering nearly 12,500 sq km offshore Angola after reaching a final agreement with national oil company Sonangol.

TGS began the survey over Blocks 36 and 37 later at the end of January and will then continue over Block 35. The industry-funded shoot is expected to complete during the third quarter this year with preliminary data available to participants in the fourth quarter. The final processed product will be available by the fourth quarter of 2013, it added.

Norway-based TGS said the blocks, which Sonangol awarded to explorations companies last month, are “highly prospective deep-water pre-salt blocks”, lying off Angola between 2000 and 5000 m below sea level.

The pre-salt basins off Angola are believed to be similar to prolific basins offshore Brazil. The planned shoot will “open a new frontier in petroleum exploration”, TGS said.

"We look forward to our new, long-term relationship with Sonangol to support oil and gas exploration in the Republic of Angola," said Rod Starr, TGS's senior vice president for Africa, Middle East and Asia Pacific. "Entry into this market is consistent with our plans for strategic growth. TGS's commitment to expanding multi-client data in the offshore areas of West Africa has extended over 10 years and we are excited to have the opportunity to now add 3D data in offshore Angola to the TGS data library."

TGS, which has chartered vessel capacity for the project, will process the 3D seismic data in both time and depth using its proven sub-salt capability developed in similar basins. Preliminary products will be available to participating companies in the fourth quarter of this year with a final processed product expected by 4Q 2013.

Oil Review Africa Issue One 2012 29

Geology & Geophysics

Circle concludes Moroccan seismic work

Geology & Geophysics

S07 ORA 1 2012 Geology_Layout 1 09/02/2012 12:31 Page 30

Multi-Client seismic survey off Namibia SPECTRUM, IN PARTNERSHIP with CGGVeritas and the National Petroleum Corporation of Namibia (NAMCOR), has commenced a new 2D Multi-Client seismic survey covering the deepwater Orange Basin, offshore Namibia.

The programme includes the Spectrum starts Orange Basin seismic survey acquisition of around 7,000 km of long offset data covering both held and open blocks in the Orange Basin. A good level of prefunding has been obtained from companies to provide support for the programme.

Seabird Exploration is providing the acquisition services through their Northern Explorer vessel which has recent experience of operating in Namibian waters. The data will be processed through full pre-stack time migration and include added-value products such as angle stacks and AVO products. Due to the frontier nature of the area, Spectrum will also be offering a ‘Fast Model’ Pre-Stack Depth Migration (PSDM) sequence, provided as part of the standard deliverables for the project. Final deliverables are expected to be available in June 2012.

Offshore Namibia is considered highly under-explored. In an area covering more than 500,000 sq km only fifteen wells have so far been drilled, seven of these in the Kudu gas field area alone. The first exploration well (Kudu 9A-1), drilled in 1973, discovered the Kudu gas field.

Over 20,000 km of high-quality 2D Multi-Client data from offshore Namibia is also available through Spectrum, in eight individual surveys. Each survey has been designed and acquired to target key structures within the offshore area.

The data vintages range from the 1989 regional survey, through detailed block specific surveys. These include the 2003 survey acquired around the Ondjou prospect in the northern Walvis Basin, a comprehensive suite of surveys around the Kudu field and those covering the Orange and Luderitz Basins.

BG wraps up Kenyan shoots BG GROUP HAS completed both a 3D and 2D seismic survey over its licence areas L10A and L10B, off Kenya.

The 3D shoot was carried out over the eastern part of the licence areas while the 2D survey was shot over the western portion of the areas.

Joint venture partner Pancontinental Oil & Gas said the surveys covered 10 leads which had been identified under a fast-track exploration programme by BG. It added some of those leads were on-trend and similar to the giant Mbawa prospect which lies to the north in the Apache-operated L8 licence.

The data from both surveys is expected to be processed by mid-2012 with interpretation and mapping to be completed later in the year.

BG is operator of both L10A and L10B with a 40 per cent and 45 per cent stake in each licence respectively,

PGS shoot in Angola pre-salt play

PGS’ Ramform Valiant starts seismic survey offshore Angola.

PETROLEUM GEO-SERVICES (PGS) has kicked off a 26,000 sq km 3D seismic survey in Angola’s pre-salt province following the approval of recent block awards in the hot play.

The shoot is being carried out in the Kwanza and Benguela basins by the Norwegian seismic contractor’s vessel Ramform Valiant, which will be joined by a second unit, PGS Apollo, next month with work set to continue until the fourth quarter. Data processing is due to start in March.

The survey is being jointly funded by BP, Total and Statoil, which recently secured operatorships on two blocks each in the deepwater Kwanza basin licensing round, and Angolan state oil company Sonangol, a partner on the acreage.

GeoStreamer data gathered from the survey will be used by the oil companies to plan their exploration well commitments on the blocks – 19, 24, 25, 38, 39 and 40 – within the next five years.

The geology of Angola’s pre-salt basins is believed to be analogous to a similar play off Brazil that has yielded huge oil discoveries in recent years, fuelling expectations among explorers.

PGS said in a statement that there is a “clear geological link”, adding “recent advances in tectonic reconstruction point to parallels with the prolific pre-salt Santos and Campos basins” off Brazil.

The region's prospectivity potential has been further raised by Maersk Oil’s recent confirmation of an oil strike at its Azul-1 exploration well in the Angolan pre-salt.

San Leon completes Moroccan seismic programme SAN LEON ENERGY HAS completed the acquisition of more than 2,280 km of 2D seismic data across its Tarfaya and Zag licenses onshore Morocco.

On the Tarfaya license, after 608 km of new high-density 2D seismic data was acquired, San Leon identified several new adjacent leads around its J North prospect. Previously, in 2008, a Competent Persons Report (CPR) from Netherland, Sewell & Associates estimated that there were 156mn barrels of recoverable prospective oil resources at J North.

In total, San Leon currently has 12 leads and prospects across the Tarfaya license, with net prospective resources amounting to 711mn boe

30 Oil Review Africa Issue One 2012

based on the 2008 CPR. San Leon said that the new seismic data quality is significantly improved compared with previous 2D seismic data in the area, and this data is currently being processed and interpreted by the company at its office in Poland.

On the Zag license, 1,674 km of 2D seismic data was acquired. This is the first seismic data ever acquired across the Zag license, where San Leon is focusing on both conventional and unconventional oil and gas potential.

San Leon said it would continue integrating the new seismic results into its existing basin model in preparation for opening a data room to seek partners for the exploration drilling phase.

"We view Morocco as a long term project for the company with significant upside over a huge unexplored area," said San Leon's Chairman Oisin Fanning. "The excitement of the potential of Morocco is based upon the significant production in the same basin in Algeria as well as the huge potential for a Silurian shale gas play. The completion of our seismic program is the next step in bringing our projects closer to drilling."

Investment bank Westhouse Securities commented: "San Leon's Moroccan acreage offers the company exciting upside at moderate cost and geological risk."

S07 ORA 1 2012 Geology_Layout 1 09/02/2012 12:31 Page 31

Geology & Geophysics

S07 ORA 1 2012 Geology_Layout 1 09/02/2012 12:31 Page 32

Dolphin secures 3D seismic acquisition contract for Polar Duke DOLPHIN GEOPHYSICAL HAS reached final agreement with Petrosen to commence acquisition of a 3D multi-client survey covering nearly 3,600 sq km offshore Senegal. The survey will commence early in March and is highly funded by the industry.

Dolphin already has 2D seismic data over this area, The Polar Duke will have a firm backlog until the end of Q3, 2012. acquired in 2011 and the acquisition of 3D data is a natural progression for these prospective areas which require better focus and defining.

Further, Dolphin Geophysical has received a LOA for additional 3D contract work and combined with the existing backlog and multi-client commitment, Polar Duke will have a firm backlog until the end of the third quarter of 2012.

Additional details will be disclosed as part of the Q4 earnings release on the 21st February 2012.

CEO Atle Jacobsen commented; "Our recent contract awards, pre-funding levels and improved visibility confirms a continued strengthened 3D seismic market.

We are pleased that both our high capacity 3D seismic vessels will be fully

Sercel acquires assets of geophysical research company CGGVERITAS’ SUBSIDIARY SERCEL has acquired the assets of Geophysical Research Company. Headquartered in Tulsa, Oklahoma (USA), and established in 1925 by Amerada Petroleum Corporation, GRC is a leading provider of downhole sensors and gauges for the oil and gas industry.

With approximately 120 employees, GRC is expecting 2011 revenues in the order of US$22mn.

This acquisition builds upon Sercel’s diversification into the well environment and more specifically the artificial lift market which shows promising growth for the coming years. GRC’s memory gauge business complements Sercel’s existing product offering and geographical coverage.

GRC products will benefit from Sercel’s technology and know-how for new product industrialisation as GRC will be launching a number of products within the next two years.

Bob Laird, CEO of GRC stated, “On behalf of GRC, our customers and employees, we are truly excited about being a part of Sercel. We clearly share common core values and the vision of providing our customers with advanced technology and value added solutions to optimise and extend the economic life of their oil and gas producing assets. This acquisition offers GRC leverage in strengthening and expanding our global presence, operational efficiency and technology offering. GRC’s management team will continue in place with Sercel.”

"We look forward to continue to expand and strengthen our footprint in downhole measurements with GRC’s product range," said Pascal Rouiller, President and CEO of Sercel. "GRC has built a strong reputation and developed a unique expertise for reliable downhole instrumentation”.

Fugro-Jason releases new version of PowerLog FUGRO-JASON, A leader in reservoir characterisation technology for the oil and gas industry, released the newest version of its flagship petrophysical software PowerLog. Significant new functionality for multiinterpreter collaboration, capillary pressure analysis, and visual presentation helps companies make faster and better drilling decisions and improve asset management.

“The multi-user, multi-interpreter functionality in PowerLog 3.3 is unprecedented,” said Eric Adams, Fugro-Jason Managing Director.

“Petrophysicists, geologists and engineers can contribute maximum expertise simultaneously on the same project in this new collaborative environment. Colleagues around the globe can view

32 Oil Review Africa Issue One 2012

wells, find pay zones and see how the reservoir connects across the field.”

"A collage of powerful visuals, automatically updated by dynamic viewers, presents field data for review by peers, senior management and clients.

"PowerLog's multi-well capability lets clients quickly view and manage thousands of wells, which is particularly appealing to those with extensive drilling programmes.

"The robust database also helps drive the adoption of corporate standards.

"Using the same tables, log scales, settings, colors and lithology patterns, organisations can push standards to every interpreter in the company so that all displays are comparable."

“Efficiency is foremost for our clients,” continued Adams, “and PowerLog truly helps our clients get their work done faster. Capabilities such as capillary pressure analysis, flexible petrophysical workflows, and portability make PowerLog the most advanced petrophysics application in the industry. It’s scalable, easy to use and a great tool for companies of all sizes.”

S08 ORA 1 2012 Gas_Layout 1 09/02/2012 12:29 Page 33

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Gas

Anadarko hits Mozambique gas ANADARKO PETROLEUM HAS struck gas across multiple zones in the Lagosta-2 appraisal well in Mozambique’s offshore Area 1.

The appraisal well was drilled using the deep-water drillship Belford Dolphin to a total depth of 4,2672 m, in water depths of about 1,467 m, and encountered 237 m of natural gas pay across multiple zones.

“This is the largest pay count of any well in the complex to date, and it seems fitting that our seventh successful well in the discovery area would encounter 777 net feet of pay,” said Anadarko senior vice president, worldwide exploration, Bob Daniels.

"These excellent results continue to support our recoverable resource estimates of 15 to 30-plus tcf of natural gas in the discovery area on our block, as well as provide additional information that will be incorporated into our models to help determine the optimal subsea development

plans for the complex. In addition, a second deepwater drillship, the Deepwater Millennium, has arrived in Mozambique to begin an accelerated testing programme that will include installing observation gauges and conducting several drillstem tests, as we remain on track to reach a final investment

decision for this project in 2013.”

In a separate announcement, joint venture partner Cove Energy said pressure readings confirmed reservoir continuity between Lagosta-2 and the Lagosta and Camarao discovery wells over a distance of 15.5 km.

Anadarko also revealed a second deep-water drillship, the Deepwater Millennium, had arrived in Mozambique to start an accelerated programme which included installing observation gauges and carrying out several drillstem tests in the Windjammer, Barquentine and Lagosta complex.

Following the completion of operations at Lagosta-2, which Anadarko said would be preserved for future utilisation during its planned drillstem testing program, the Belford Dolphin will be mobilised to spud the Lagosta-3 appraisal well.

Offshore Area 1 covers 2.6 mn acres in the Rovuma basin and has been estimated to hold between 15 and 30 tcf of recoverable gas.

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34 Oil Review Africa Issue One 2012

S08 ORA 1 2012 Gas_Layout 1 09/02/2012 12:29 Page 35

Shale gas battle pops up in South Africa threat to the country's overall energy security.

The country is looking at ways to shift its dependency on coal. A government plan proposes nearly halving the share of coal in the country's energy mix to 48 per cent by 2030 from about 90 per cent today, using renewable energy such as wind and solar. In November last year, state-utility group Eskom received a loan from the World Bank to finance the building of the country's largest solar energy and wind power generation projects.

The country was rocked by power cuts in

2008, sparking one of worst crises in its history with the national grid brought to near collapse.

With the help of outside funding, Eskom has been recommissioning older power stations that had been mothballed but it also warns that domestic demand will exceed supply until at least 2013 when the first new power stations will be brought online.

Aside from Shell, other companies interested in exploring in the Karoo include the US' Falcon Oil & Gas and Australia's Sunset Energy.

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Oil Review Africa Issue One 2012 35

Gas

IN FEBRUARY, A government-imposed moratorium on exploration for shale gas in South Africa expires and although it is not expected to be extended, there remains uncertainty that work will proceed in the country as normal.

Over the last two years, the subject of developing shale gas resources in the semi-arid Karoo region, thought to contain trillions of cubic feet of shale gas, has stirred emotional debate throughout South Africa. Public concerns have focused on hydraulic fracturing, in which drillers blast millions of litres of water, sand and chemicals into shale formations to release natural gas. Critics say the process could lead to contamination of water supplies in the sensitive Karoo environment.

Opponents include Treasure the Karoo Action Group (TKAG), Greenpeace and local farmers who want to know whether fracking can work without damaging the environment, where the massive amount of water needed will come from and what investment opportunities are there.

The biggest critic, TKAG, says most people in the small towns and farms of the Karoo have not been informed of the dramatic effect fracking for gas could have on their livelihoods and health.

Proponents believe it is a potential gamechanger in South Africa's desperate search for energy sources. The International Energy Agency, which estimates the Karoo might hold reserves of 485 tcf, says shale gas could not only improve energy security but also would reduce greenhouse gas emissions.

Shell, which has submitted an application for rights to explore 80,000 sq km of the region, says shale gas in the Karoo would make South Africa energy self-sufficient for decades.

South Africa has very limited oil reserves, and imports from the Middle East and Africa meet about 95 per cent of the country's oil requirements. Excessive dependence on imported oil from high-risk regions makes the country vulnerable to both economic and national security problems, and high oil prices are a major

S08 ORA 1 2012 Gas_Layout 1 09/02/2012 12:29 Page 36

Gas

GE Oil & Gas launches Micro LNG integrated plant

Factory / Head Office: P.O. Box: 31691 Al-Khobar 31952 K.S.A Tel: +966 3 812 1066 Fax: +966 3 812 2253

GE OIL & GAS has announced the development of a Micro LNG integrated plant that meets the smallscale liquefied natural gas (LNG) requirements of powering remote industrial and residential locations and fueling motor vehicles.

GE’s Micro LNG plant produces in the range of 50 to 150,000/tons per year of LNG. The biggest difference between traditional large plants, which produce in excess of one million tons per year, and Micro LNG is the end user the product is destined for. For the large LNG plant, the product is produced for international export, where plant economy of scale is among the most important factors. In Micro LNG, the distributed production is primarily aimed at local markets, where it is regasified and fed as pipeline natural gas or used for local power generation.

GE’s Micro LNG plants are simple to install, operate and maintain and are customised to meet specific customer and site requirements.

“GE Oil & Gas is a recognised leader in all segments of the oil and gas industry, with a strong focus on LNG,” said Andrew Way, vice president of global services for GE Oil & Gas. “Over the years, we have developed complex, large-scale turbocompression machinery required for LNG applications. By leveraging our proven expertise, we now have developed a specific solution to address smaller-scale requirements.”

Typically, the equipment GE will supply directly for the Micro LNG plants will include centrifugal and integral gear compressors and companders, turboexpander compressors, reciprocating compressors and controllers, providing real-time connectivity and integration to greatly simplify production processes.

In addition to the process design, turbomachinery equipment and control, the Micro LNG system includes one of the first applications of the Waukesha gas engines for mechanical drive and power generation that became part of GE’s broad portfolio following the US$3bn Dresser Inc, acquisition in 2011.

GE’s Micro LNG technology supports a growing global demand for LNG. Besides being a more environment-friendly alternative to diesel in heavy duty vehicle freight transportation and extra heavy duty off-road vehicles, LNG also is a suitable substitute for diesel or fuel oil for powering remote locations and can be used to capture methane fugitive emissions typically related to mining or upstream oil operations eligible for World Bank financing and emissions allowances. The GE system is a cost-effective solution to manage gas peak demand and more in general for gas transportation and storage.

Using LNG as a substitute for diesel or fuel oil can reduce combustion emissions up to 25 per cent.

GE’s Micro LNG system is part of a growing portfolio of products that have been qualified under GE ecomagination. To earn ecomagination qualification a product is evaluated for its ability to significantly and measurably improve the customer’s environmental and operating performance.

S09 ORA 1 2012 Exploration 01_Layout 1 09/02/2012 12:27 Page 37

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E&P

Maersk hits oil pay offshore Angola SOCIEDADE NACIONAL DE Combustíveis de Angola Empresa Pública, Maersk Oil and other partners declared the Azul-1 deepwater exploration well, located in Block 23 in the Kwanza Basin, a discovery well.

The Azul-1 well, the first to penetrate pre-salt objectives in Angolan deepwater, was drilled in water depths of 923 m and reached a final depth of 5,334 m. The condition of the well prevented an assessment of flow capacity by a conventional test. This was performed as a mini-Drill Stem Test that enabled the recovery of two good quality oil samples.

The preliminary interpretation of the data indicated a potential flow capacity greater than 3,000 bpd of oil. Taking into account these encouraging results, Maersk Oil will further evaluate the results of this discovery and will proceed with exploration work in the block.

Sonangol E.P. is the block Concessionaire. Maersk Oil is operator of Block 23 with a 50 per cent working interest with partners Svenska and Sonangol P & P. "We are encouraged by the results of our first pre-salt exploration well in this region, which was also the first ever deep water well targeting presalt reservoirs in the Kwanza Basin. The result may be a further step towards our goal of building up a significant business in Angola," said Lars Nydahl Jorgensen, Head of Exploration at Maersk Oil. "There is substantial evaluation work ahead of us to determine whether the discovery is enough to invest further to get production going. This will be done by, amongst other things, state of the art reprocessing of seismic data. Fully appraising the discovery will take several years and it is far too early to guess the outcome," Jorgensen said.

Ophir grabs Eirik Raude GREEK RIG OWNER Ocean Rig has tied up one of its drilling units with Ophir Energy for a three-well programme off West Africa.

Financial details of the deal which will see the semi-submersible Eirik Raude stationed off Equatorial Guinea have, however, been kept under wraps.

Ophir is taking the drilling rig for around 60 days beginning in April to drill the three firm wells on Block R with an option for one more, it revealed..

The first well is to be near the Fortuna gas discovery with the second the Tonel-1 and the Silenus East-1.

Ocean Rig announced in mid October that a UK independent and a US counterpart had signed on for the drilling of three wells with the Eirik Raude off West Africa in deals worth a total of US$96mn. Tullow and Anadarko were behind those deals off Ghana and Ivory Coast, respectively.

Total wins Mauritania licence duo TOTAL HAS SCOOPED a pair of exploration licence awards in northwestern Africa in which it will be operator with a significant stake.

The French supermajor has taken a 90 per cent slice in both licences in Mauritania, one of which is onshore and the other in ultra-deep water.

Total will operate Block C 9 off the coast of the African country while also taking on Block Ta 29 onshore in the Taoudeni basin.

The oil giant said the offshore award will see it enter into "a highpotential, frontier play, known as the abrupt margin, in which major discoveries have been made recently," pointing to successes off French Guiana.

Senior vice president of exploration Marc Blaizot continued: "The license award is aligned with Total’s strategy of expanding its exploration operations into high-potential geological plays while leveraging the group’s globally recognised ultra-deepwater expertise."

Block C 9 is situated about 140 km off Mauritania in water depths ranging between 2500 and 3000 m. The block covers an area of some 10,000 sq km.

Block Ta 29 is around 1000 km east of the capital Nouakchott in the Saharan desert. It is situated just north of Block Ta 7 in which Total already has a stake.

"The new onshore block is on the same trend as onshore Block Ta 7 on which latest exploration results show good prospectivity in this part of the Taoudeni basin," Blaizot continued.

A seismic acquisition programme is planned for both new blocks.

Total has been active in exploration in Mauritania since 2005 through Block Ta 7 and Ta 8, also in the Taoudeni basin, 800 km east of Nouakchott.

Kosmos in new Cameroon project US PLAYER KOSMOS Energy signed an agreement with Cameroon's state oil company SNH allowing it to explore in the central African state's offshore Fako block, a report said.

Kosmos will invest US$17.56mn to explore within the 1,289-sq-km block, which sits near Cameroon's productive Rio del Rey and Kribi-Campo basins, for six years, Reuters reported.

The deal was signed by the vice president of Kosmos' Cameroon subsidiary Christopher Stone and SNH manager Adolphe Moudiki, SNH said.

It adds to Kosmos' exploration efforts in

38 Oil Review Africa Issue One 2012

two other Cameroon blocks, Kombe-N'Sepe and Ndian River.

Kosmos, backed by private equity firms Blackstone Group and Warburg Pincus, is focused on frontier areas in Western Africa and South America.

It helped discover in 2007 the Jubilee oil field offshore Cameroon’s oil blocks.

Ghana, which began pumping in late 2010. around 65,000 bpd from 185,000 bpd at its Cameroon is one of Africa's oldest oil peak in 1985. producers but has seen output slump to

S09 ORA 1 2012 Exploration 01_Layout 1 09/02/2012 12:27 Page 39

Tullow hits oil at Ntomme off Ghana potential for an oil column at Ntomme of approximately 125 m below the gascondensate accumulation,” it added.

Operator Tullow drilled the Ntomme-2A well to an interim depth of 3905 m in water of 1730 m.

The company is in the process of deepening the well to a total depth of 4,010 m, after which it will run a drill stem test.

Tullow operates the Deepwater Tano Block with a 49.95 per cent working interest.

Kosmos and Anadarko Petroluem each own an 18 per cent stake, with Sabre Oil & Gas Holdings on 4.05 per cent and Ghana National Petroleum Corporation on a 10 per cent carried interest.

Kosmos also announced the completion of sidetrack operations at the J-7 well at the Jubilee project, which was drilled to test a new well-completion design resulting from near wellbore productivity issues. The sidetrack was flow tested at a rate of up to 15,000 bpd of oil.

Kosmos said the well started producing

E&P

TULLOW OIL HAS hit “significant quantities” of light oil in an appraisal well in the Deepwater Tano Block off Ghana.

The Ntomme-2A appraisal well – located about four km south of the Tweneboa-3 sidetrack, which discovered the Ntomme field – hit 45 m of high-quality stacked reservoir sandstones, including 39 m of 35°API gravity net oil pay, partner Kosmos Energy said.

Paul Dailly, Senior vice-president of exploration for Kosmos called the find a “great result” because Ntomme was originally identified as a gas-condensate discovery.

“However, this well confirms the majority of resources to be oil,” he said in a statement.

Ntomme-2A was designed to test the potential for an oil leg beneath the previously identified gas-condensate at Ntomme, Kosmos said.

“Pressure data from the well and the original discovery well suggests the

Anadarko well strikes oil offshore Ghana.

earlier this month. Operator Tullow is gradually increasing production to monitor the performance of the completion design, Kosmos said.

Tullow expects to perform sidetracks on three additional Phase 1 wells this year at a total cost of about $400mn.

Jubilee partners, including Anadarko Petroleum, Sabre Oil & Gas and Ghana National Petroleum Corporation, are also analysing other remediation possibilities such as workovers or stimulation efforts, Kosmos said.

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Oil Review Africa Issue One 2012 39

S09 ORA 1 2012 Exploration 01_Layout 1 09/02/2012 12:27 Page 40

E&P

APC spuds second Liberia deepwater wildcat Total to get to work on Congo block AFRICAN PETROLEUM CORPORATION has begun the Narina 1 well on block LB-09 offshore Liberia with the Maersk Deliverer semisubmersible drilling rig.

The well targets a Turonian prospect that APC estimates to hold potential recoverable oil of 500 to 1,200 mmbbl, and follows drilling of the Apalis 1 well in 2011 in the same block.

CEO Karl Thompson said: “Apalis 1, the first well in deepwater offshore Liberia, proved a working Map of African Petroleum’s Prospect portfolio on hydrocarbon system in the Blocks LB-08 and LB-09. basin and our second well will target Turonian sands similar to the oil bearing reservoirs in Ghana and Sierra Leone.”

FRENCH OPERATOR TOTAL will be able to start its Block III work programme in the Democratic Republic of Congo following government approval.

Block partner SacOil said a Presidential Ordinance had been granted in respect to Total’s 60 per cent interest in the block.

“The granting of the ordinance is a significant step for progressing the asset in that the required testing and evaluation of the oil and gas prospects can begin in earnest,” SacOil chief executive Robin Vela said.

“We believe that there is huge potential in this asset due to the neighbouring oil and gas discoveries in Uganda which suggest that Block III is in an attractive and hydrocarbon prospective address.”

The Presidential Ordinance will allow Total to commence a previously approved US$30mn work programme this year which will include an airborne gravity and magnetic survey and the acquisition of a 2D seismic survey on the northern area of the block.

If it is able to positively identify potential oil and gas structures from the surveys, Total also plans to drill an exploration well to determine the potential and commercial viability of Block III. SacOil farmed out a 60 per cent interest in Block III to Total in March last year and will be carried for the entire work programme and will not need to contribute any further capital into the project until a final investment decision on any potential development plan.

BP expands deepwater offshore Angola

CAMAC bags blocks offshore The Gambia

BP HAS GAINED access to five more deepwater exploration and production blocks offshore Angola. These give BP a leading position in Angola, with interests in nine blocks accounting for a total acreage of 32,650 sq km.

In a recent ceremony in Luanda, in the presence of state oil company Sonangol's president Manuel Vincente and BP group chief executive Bob Dudley, the production sharing agreements were signed for four new blocks covering 19,400 sq km in the Kwanza and Benguela basins.

Separately, BP has recently taken a 40 per cent stake in the 4,840 sq km Block 26 in the Benguela basin, by agreeing a farmin deal with Brazilian national oil company, Petrobras, which operates the block.

"In October, we told the markets we would build on our strengths in exploration and in the deepwater to provide future growth for BP. This new access builds on the major presence we have developed in Angola over the past 10 years, investing a total of US$21bn in the business. We plan to double our global spend on exploration and this huge new acreage gives us more great opportunities. We look forward to working with Sonangol in the Kwanza and Benguela basins," said Bob Dudley. "The last 14 months have been our most successful for a decade in gaining new access for exploration - with 69 new exploration licences in 11 countries."

BP already has stakes in four blocks in Angola - Blocks 15 & 17 non-operated; 18 & 31 BP-operated. BP has production from Blocks 15, 17 and 18. Reported production in 2010 was 170,000 net barrels per day (bpd).

BP's exploration programme on Block 31, deploying leading seismic imaging technologies, has so far led to 19 discoveries, five of which are subsalt, traditionally difficult to image.

BP expects its first development in Block 31, PSVM, to start production in 2012 producing 150,000 gross bpd at plateau. BP's share is 26.67 per cent.

The geology of the Kwanza and Benguela basins is thought to mirror Brazil's hydrocarbon-rich pre-salt regions. BP has interest in 10 blocks offshore Brazil through last year's acquisition of Devon Energy assets.

CAMAC ENERGY HAS entered into an agreement with the Gambian Ministry of Petroleum (on behalf of the Government of the Republic of The Gambia) on the provisional award of two offshore exploration blocks, A2 and A5, in water depths of between 600 and 1,000 m. CAMAC Energy will be the operator with 85 per cent interest in the blocks, which cover a total surface area of 2,666 sq km.

Gambia National Petroleum Company will be carried at 15 per cent through first oil. The agreement sets forth the negotiated fiscal terms and work programme for the two blocks, and this award is subject to submission of an Environmental Impact Assessment (EIA) and signing of final petroleum exploration licenses within 90 days.

The EIA report has now been submitted by the company, and signing of the license documents is expected in the next few weeks.

The two exploration blocks are located in the highly prospective West African Transform Margin, home to several recent major discoveries in Ghana (Jubilee, Odum) and Sierra Leone (Venus, Mercury). In addition, in 1979 Chevron drilled the Jammah-1 well on the basis of sparse 2D data in block A2. The well had gas shows, thereby establishing the presence of hydrocarbons in the area. More recently, extensive 3D seismic shot on the two Gambian blocks A1 and A4, immediately west of the blocks A2 and A5, has revealed a number of material prospects and leads according to the operator, African Petroleum Corporation.

According to African Petroleum's third party estimates, one of the prospects, the Alhamdulilah prospect, has potential mean unrisked resources of approximately 500mn barrels.

Chairman and CEO Dr. Kase Lawal commented, "We are extremely pleased to be awarded these two blocks. Gambia's blocks A2 and A5 represent highly sought after assets in one of the world's most exciting hydrocarbon provinces, the West African Transform Margin. Today's announcement demonstrates additional progress in our frontier exploration strategy. It also reaffirms the company's reputation as a value added oil and gas partner to National Oil Companies in Africa."

40 Oil Review Africa Issue One 2012

S10 ORA 1 2012 Exploration 02_Layout 1 09/02/2012 12:26 Page 41

E&P

S10 ORA 1 2012 Exploration 02_Layout 1 09/02/2012 12:26 Page 42

Ngamia well spuds in Kenya

Aker boosted in Ghana

PARTNERS TULLOW OIL and Africa Oil Corporation have spudded a well at a closely-watched onshore prospect in Kenya.

The Ngamia-1 well was spudded at Block 10BB and will be drilled to a projected depth of 2,700 m to test the oil potential in Miocene age sandstones, with drilling and evaluation expected to take between two and three months.

Tullow Oil operates the licence on a 50 per cent working interest, with Canada’s Africa Oil holding the other half.

The partners believe the prospect to be tested is similar to those drilled by Tullow in Uganda’s Lake Albert rift basin.

Africa Oil chief executive Keith Hill said Tullow has “had enormous success with the Lake Albert Rift Basin project where in excess of 1 billion barrels have been discovered, and this shares many geological similarities”.

The well is located in the Lokichar basin, where live oil was encountered by the Loperot-1 well in 1992 that recovered 29°API crude from Miocene sandstones, according to Africa Oil. “Our Ngamia prospect could be a play opener for another great success in the region," he added.

It is the first of a multi-well drilling programme at the block and adjacent prospects.

The high-profile onshore wildcat in Kenya is expected

AKER SOLUTIONS WILL provide well intervention services for Tullow Ghana’s Jubilee and Tano deepwater fields under a contract Aker said would generate revenues of about US$4mn.

Under the agreement Aker Solutions will provide slickline and coiled tubing equipment and services, which are conducted with the objective of maximising production of oil and gas. Aker has worked on Tullow’s Jubilee field since 2008.

The initial contract period is for three years, with two additional oneyear options (3+1+1).

Aker head of well intervention solutions Wolfgang Puennel said the deal would give the company a solid long term outlook for their operations.

“We will utilise this to set up a more permanent presence in Ghana, which will also drive the need for a larger local workforce. This will put us in a better position to secure further oil service work in the country," he said.

to kick off an ambitious wildcatting campaign in the rift plays of Kenya and Ethiopia in the coming years by the London-based independent.

Keith Hill, President and CEO of Africa Oil, commented, "We are very excited to be drilling our first well with Tullow. They've had enormous success with the Lake Albert Rift Basin project where in excess of one billion barrels have been discovered and this shares many geological similarities with our Kenyan assets. Our Ngamia prospect could be a play opener for another great success in the region."

Uganda expects 2013 Tullow production

Oando deploys rig for Shell's Niger drilling

UGANDA'S ENERGY MINISTER has said that commercial oil production could begin as early as next year after London-listed Tullow Oil signed two productionsharing agreements with Oil exploration at one of Tullow's blocks in Hoima. the country.

"If I may give a tentative period, then maybe in a year," Ugandan Energy Minister Irene Muloni said on the sidelines of an annual mining conference in Cape Town.

Muloni announced details of the deal, which she said included Tullow agreeing to build a refinery.

Tullow must now finalise "farmdown arrangements" with China's CNOOC and France's Total. A farmdown involves a licence holder inviting other operators to help develop a prospect and share the spoils.

"CNOOC and Total are to submit their development plans," Muloni added.

She said the crude would be used for power generation.

Uganda discovered oil in the west of the country, along the border with the Democratic Republic of Congo, in 2006.

Production had been expected to start early this year but wrangling over tax and other issues delayed development.

Tullow has 1.1bn confirmed barrels of oil in Uganda and believes there are 1.4bn left to find, Reuters reported.

OANDO ENERGY SERVICES (OESL), Nigeria's leading indigenous operator of swamp drilling rigs, has announced the deployment of one of its swamp rigs, OES Passion, to execute a two year drilling contract, valued at N12bn with Shell Petroleum Development Company (SPDC) in the Niger Delta. This brings to three the number of rigs OESL has in operation following the deployment of OES Integrity in 2009 and OES Teamwork in 2010.

OES Passion is a unique swamp barge with sequential well drilling capabilities and a skidding system that enable it drill up to six wells in one location. Formerly known as Parker 75, the rig entered into service in 1999 and it is rated to 3000HP, thereby able to drill up to 7,620 m in water depths of up to five metres.

To ensure optimal performance on deployment, OESL committed to a comprehensive lifetime enhancement programme after purchasing the rig in 2009. This upgrade included the restoration of the cantilever skidding system which is expected to save the client up to 30 days for every six wells drilled thus significantly reducing the overall cost of drilling campaigns. Also modernised were the mud pumps, the electric-motor driven engines, the top drive and the accommodation module.

With a technical team that was 99 per cent constituted by Nigerians, several competent indigenous contractors, and the refurbishment project undertaken at the Federal Lighter Terminal in Onne, Port Harcourt, this project is a testament of Oando's support for the Nigerian Oil & Gas Industry Development Content Act and local capacity development program of the Federal Government.

According to Mr. Bandele Badejo, Chief Executive Officer of OESL, "The deployment of this rig further underlines OESL's commitment to ensuring competent indigenous companies take advantage of the provisions of the Nigerian Oil & Gas Industry Development Act. We remain resolute towards developing Nigeria's upstream service industry and continue to set the benchmark for performance. Following the success of our previously deployed rigs, OESL has built a reputation as the drilling contractor of choice among the major oil companies and we will not relent in our mission to be the upstream preferred supplier of choice as we strive to achieve better operating efficiencies and better safety performance for our clients and other stakeholders."

42 Oil Review Africa Issue One 2012

S10 ORA 1 2012 Exploration 02_Layout 1 09/02/2012 12:26 Page 43

S11 ORA 1 2012 Rig Count & Downstream_Layout 1 09/02/2012 19:12 Page 44

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.

DECEMBER 2011 - LAND & OFFSHORE THIS MONTH Country ALGERIA (1) ANGOLA CAMEROON (1) CHAD (1) CONGO DRC (1) EQUATORIAL GUINEA (1) ETHIOPIA (1) GABON GHANA (1) IVORY COAST (1) KENYA LIBERIA LIBYA*** MAURITANIA (1) MOROCCO (1) MOZAMBIQUE (1) NIGERIA SENEGAL SOUTH AFRICA TANZANIA (1) TUNISIA UGANDA (1) TOTAL

Land OffShore Total 28 0 28 1 7 8 0 0 0 2 0 2 1 2 3 0 0 0 0 2 2 0 0 0 3 2 5 0 2 2 0 0 0 1 0 1 0 1 1 0 0 0 0 0 0 0 0 0 0 2 2 5 14 19 0 0 0 0 0 0 0 2 2 3 0 3 0 0 0 44 34 78

VARIANCE From Last Month -5 0 -1 0 1 0 1 0 -1 0 -1 0 0 0 0 0 0 2 0 0 1 2 0 -1

LAST MONTH Land OffShore Total 33 0 33 1 7 8 0 1 1 2 0 2 0 2 2 0 0 0 0 1 1 0 0 0 5 1 6 0 2 2 0 1 1 1 0 1 0 1 1 0 0 0 0 0 0 0 0 0 0 2 2 5 12 17 0 0 0 0 0 0 0 1 1 1 0 1 0 0 0 48 31 79

LAST YEAR Land OffShore Total 32 0 32 0 8 8 1 1 2 2 0 2 2 1 3 0 0 0 0 0 0 0 0 0 3 1 4 0 1 1 0 0 0 0 0 0 0 0 0 14 1 15 0 1 1 0 0 0 0 0 0 7 7 14 0 0 0 0 0 0 0 1 1 3 0 3 0 0 0 64 22 86 Source: Baker Hughes

Total fires up Ofon phase two FRENCH OIL MAJOR TOTAL has announced that the second phase of the Ofon field development in offshore Nigeria (Ofon Phase 2) has begun.

Construction and installation contracts have been awarded for Ofon Phase 2, which is scheduled to come on stream in 2014.

The Ofon field is located in Oil Mining Lease (OML) 102, 65 km off the Nigerian shores in a water depth of 40 m.

Ofon Phase 2 will unlock the field’s undeveloped reserves to increase production to 90,000 barrels of oil equivalent per day from 30,000 barrels, by installing four new platforms: two production platforms, a processing platform and an accommodation platform. Most of the development is dedicated to recovering natural gas, which will be compressed and evacuated to shore.

In line with Total’s environmental stewardship commitments, Ofon Phase 2 is a major step forward in the Group’s plan to reduce its flaring of associated gas and its greenhouse gas emissions.

“In launching Ofon Phase 2, Total is increasing the pace of development of its resources in a sustainable manner,” commented Jacques Marraud des Grottes, Senior Vice President, Exploration-Production for Africa at Total. “It is a further growth driver supporting our strategy, which is primarily focused

44 Oil Review Africa Issue One 2012

on developing deep offshore fields such as Akpo and, in the near future Usan by minimizing its greenhouse gas emissions.”

The partners in OML 102 are Total Exploration-Production Nigeria Ltd (40 per cent, operator) and Nigerian National Petroleum Corporation (NNPC – 60 per cent).

Source: www.slb.com

S11 ORA 1 2012 Rig Count & Downstream_Layout 1 09/02/2012 12:07 Page 45

Downstream

S11 ORA 1 2012 Rig Count & Downstream_Layout 1 09/02/2012 12:07 Page 46

Lanuf refinery to start up 'in the next few months’ LIBYA’S LARGEST REFINERY, Ras Lanuf, will resume output within months and will be expanded to double its current capacity over four years, a joint venture partner has said.

Abdul Aziz Al Ghurair's Dubaibased group set up a joint venture with the Libyan National Oil Corporation in 2009 - the Libyan Emirati Refining Co to own and operate the refinery. Ras Lanuf can process up to 220,000 bpd and accounts for well over half of the country's total oil refining capacity. The refinery was halted during last year's uprising against the rule of Muammar Gadaffi and the reopening date has consistently been pushed back. The NOC had hoped to have the refinery back up at the end of 2011.

"We are looking at getting it to start again - in the next few months," Al Ghurair, who is part of a trade delegation from the United Arab Emirates, told reporters in Tripoli. While the current focus is on getting the

refinery operational again - Al Ghurair said it was "slightly" damaged during the country's civil unrest - the aim was to expand it going forward.

"We are looking to expand, to double the capacity, so once we have the expansion plan it should be doing 400,000 bpd," Al Ghurair, who is chief executive of Mashreq bank, Dubai's second-largest lender by market value, said. "It will take four years to complete the expansion."

Al Ghurair cautioned that the speed of the refinery's build-out would be dictated by market conditions. The UAE was the second Arab state to recognise the Transitional National Council as the legitimate government of the North African country and, along with Qatar, was the only Arab country to offer military assistance to NATO operations against former leader Muammar Gaddafi.

"What we are looking at, UAE companies, is to come and set up shop quickly," Al Ghurair said.

South Sudan inks Kenya pipeline deal TENSIONS BETWEEN SUDAN and South Sudan are set to rise even further as the latter finally put pen to paper on a controversial pipeline deal with Kenya.

The African neighbours signed a memorandum of understanding to build the pipeline linking oilfields in the world’s newest nation to the Kenyan port of Lamu close to the Somali border. The country’s deputy Petroleum and Mining Minister Elizabeth James Bol said construction should take about 11 months.

The issue of raising funds for the pipeline is complicated by the recent shutting-in of oil production in South Sudan in response to the perceived “theft” of its resources by Sudan to the north.

He continued: “Insomuch as the duration of revenue disruption is unknown and to ensure the continued operation of our national government and to provide for our people, we will need to find other sources of funding.

“In doing so, I have instructed the Ministry of Finance to initiate contingency plans for revenue collection and allocation. This will accelerate the increase in collections of non-oil revenues. It also will prioritise the allocation of existing revenue, allowing us to make the most of what we have.

“The Ministry of Finance will also look into other options for replacing the lost revenue. On existing cash reserves, rest assured that the government can operate for the immediate future, depending on which cuts are made.”

The firming up of the agreement with Kenya, which has been long mooted, is likely to harden Sudan’s stance on oil from the South.

Landlocked South Sudan split from Sudan in July taking about three quarters of the previous country’s roughly 500,000 bpd of oil production, but it still relies on Sudan's infrastructure to export crude.

The two have yet to hammer out a definitive agreement on the sharing of oil revenues which has led to the unilateral action from Sudan on cargoes heading through its infrastructure for export.

DSI wins Egypt Petchem contract DRAKE & SCULL International (DSI) has secured a construction deal for a mining grade ammonium nitrate facility worth US$39mn in the Ain Sukhna province of Egypt. The company is a giant in the segment of delivering world-class integrated planning, engineering and building. The plant will be completed in April 2014.

The Drake & Scull Water and Power (DSWP) commenced its dedicated regional oil and gas arm in 2010 and the latest deal win of the company is its first project in Egypt’s petrochemical segment after starting of its specialised division. The DSWP has inked a strategic JV accord with Egypt’s leading general contracting company Hassan Allam Construction to accomplish the project.

According to a DSWP spokesman, the range of work within the project will include general construction and pre-commissioning of civil works, mechanical equipment and building of storage tanks, pipe laying and structural steel fabrication as well as other related construction works.

Egypt Hydrocarbon Corporation will develop and run the petrochemical plant, which has a nitric acid and ammonium nitrate division, along with connected infrastructure and facilities such as storage tanks, pipelines as well as other units. After the plant becomes operational in April 2014, it will have the capacity to make mining grade ammonium nitrate of 1,060mn tpd for delivering in the mining and construction industries.

The DSWP MD Mr Tawfiq Abu Soud has said that the deal reflects a premeditated landmark success for the company in Egypt. “Since the establishment of our regional oil and gas EPC specialised division in 2010 we have been aggressively engaged in partnering with regional and multinational companies to expand our market reach and optimise our service offering in this sector.”

Mr Abu Soud said, “Our partnership with a longstanding market leader such as Hassam Allam Construction will allow us to expand in this promising industry whereby our unified multidimensional portfolio and regional expertise will enable us to cover the complete value chain of petrochemical sector.”

46 Oil Review Africa Issue One 2012

S12 ORA 1 2012 Technology 01_Layout 1 09/02/2012 12:48 Page 47

Technology

S12 ORA 1 2012 Technology 01_Layout 1 09/02/2012 12:22 Page 48

Cygnus Instruments, the pioneer of multiple echo digital thickness gauges, has recently announced its new partnership with Engineering Automation Technology Ltd (EA TECH)* in Nigeria.

New ultrasonic thickness guage partnership

in West Africa U

NTIL NOW THERE have been few sales and no technical support of ultrasonic thickness gauges and leak detectors in West Africa.

However that has now changed. Following in-depth technical training in the UK at Cygnus’ Headquarters, the team at EA TECH is now an Authorized Cygnus Distributor and Service Centre. EA TECH’s engineers are trained to carry out calibrations and after-sales support of the full range of Cygnus ultrasonic thickness gauges and leak detectors.

Emmanuel Okon, the Managing Director of EA TECH, is a keen supporter of the Nigerian government’s ongoing reforms in the oil industry to empower and enable local firms and contractors. These reforms, including the “Local Content Law”, combined with the rate of spills and leakages that are currently occurring in the West African oil and gas industry, enabled Mr Okon to identify the need to bring very high quality, simple and robust Non Destructive Testing (NDT) products into Nigeria and West Africa.

Internal corrosion Oil and gas pipelines suffer from internal corrosion leading to costly leaks and emergency repair work. When carrying out any repair work pipe wall thickness must be determined when planning the job. Complicating this process, pipelines often have protective coatings such as plastics or coal-tar.

Removing these coatings is costly and impractical and renders the area prone to future accelerated corrosion. So, any thickness gauge needs to read the pipe wall thickness through such coatings…

Cygnus has developed its technology over nearly 30 years, precisely to meet these Inspection, Repair and Maintenance (IRM) needs. The use of a Cygnus multiple echo thickness gauge enables an operator with little or no training to take accurate, reliable and repeatable measurements of remaining metal thickness without removing protective coatings. Additionally the 'Deep Coat' mode can measure through coatings up to 20 mm thick.

North Sea diver taking thickness measurements (with the new Cygnus DIVE) on an offshore structure.

storage tanks. These are typically designated hazardous areas and therefore must conform to tough safety regulations. As a result, what are essentially routine inspections of metal thickness require a hot work permit and certified inspection, which is costly. The expense is also increased when the pipeline or storage tank coatings have to be removed through grinding or chipping, which cause sparks that further heighten risk. The Cygnus 1 Intrinsically Safe is a solution to these problems as it is able to gauge metal thickness without needing to remove the coatings and without needing to apply for a hot work permit. Inspections can be carried out while operations run as normal. EA TECH also supplies the Intrinsically Safe leak detector in the Cygnus range, another product which negates the need to obtain a hot work permit in the explosive environments, common to the oil and gas sectors.

Subsea thickness gauging The Cygnus name is particularly strong in the offshore industry, both with divers and ROV operators. The Cygnus thickness gauges, with robust housing, are reliable in the harshest operating environments. The Cygnus DIVE is a new wristmounted gauge for divers (300msw) that has a live A-Scan display. Made from a tough glass-filled resin, the Cygnus DIVE can withstand the knocks and bumps of the diving environment. A large bright colour TFT screen displays the thickness measurements in big numbers that really stand out.

Also, trusted by divers for nearly 30 years, the Cygnus Underwater uses the multiple echo technology. With three types of ROV-Mountable gauges, suitable for observation ROVs through to Work-Class ROVs (depth-rated 4000 msw), Cygnus has recently developed dedicated ROV probehandling solutions. ■

One of the most common applications for ultrasonic thickness gauges is the inspection of pipelines and storage tanks.

This saves time and money on labour, training and whilst carrying out the inspection. It can even forego the need for specialist contractors normally associated with inspection and maintenance work.

The Cygnus range provides thickness gauges to cover all predictive maintenance and corrosion monitoring needs of the oil industry, whether for rope access, offshore, ship survey or in hazardous environments.

Thickness gauging environments

in

hazardous

One of the most common applications for ultrasonic thickness gauges is the inspection of pipelines and

48 Oil Review Africa Issue One 2012

Thickness gauging with the Cygnus Intrinsically Safe (I.S.) in a potentially explosive environment

*EA TECH is a Lagos-based Engineering company which utilises certified, qualified and experienced personnel to provide high quality and professional services in the Oil & Gas sector.

S12 ORA 1 2012 Technology 01_Layout 1 09/02/2012 12:22 Page 49

• • • • •

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Tel: 084 463545

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E-mail: marlin_maritme@yahoo.com Website: www.marlinmaritime.com

S12 ORA 1 2012 Technology 01_Layout 1 09/02/2012 18:05 Page 50

Technology

Advanced NDT inspection delivers cost-effective solution for identifying corrosion under pipe supports - by Lews Colman*.

Managing corrosion -

a key challenge

SAPREF’s refinery in Durban, South Africa.

M

ANAGING CORROSION IS one of the key challenges facing operators in their drive to maintain an asset(s) integrity. Assessing, inspecting and repairing corrosion will help ensure compliance with statutory and corporate HSE requirements and can help reduce the likelihood of environmental and safety hazards and incidents.

While corrosion to elements of an asset such as walkways, valves and cable trays, are easy to visually identify, inspecting corrosion under process pipe supports poses a number of major challenges.

The restricted access and visual impairment of the pipe support to pipework geometry means many conventional forms of non destructive testing are not effective.

This has led to operators lifting areas of process pipework away from the supports to inspect the contact point areas. However, lifting operations are likely to cause significant disruption to the process plant operations.

Recognising this issue, Stork Technical Services (Stork) (previously RBG Limited) and Verkade NDT Services (Verkade) utilised an advanced nonintrusive NDT technology with rope access solutions to inspect corrosion under supports (CUS) at SAPREF’s (Shell and BP South African Petroleum Refineries (Pty) Ltd) refinery in Durban, South Africa.

Causes of CUS Corrosion at pipework to pipe support contact points is a leading cause of process piping failure and occurs when the pipework moves due to changing temperatures during operating service.

Frictional forces between the pipework and pipe support can cause damage to the protective coating

50 Oil Review Africa Issue One 2012

system and if not properly managed can result in unplanned shutdowns for remedial activity. The rate of corrosion is affected by a number of issues including mechanical damage, fabrication design and variations in temperature.

6 Mechanical damage Manual handling during installation may cause damage to the protective coating system. The coating may also suffer mechanical damage due to in-service movement and activity.

6 Fabrication design The geometry caused by poor fabrication techniques and installation can lead to the formation of moisture and debris traps which result in a corrosion cell or crevice corrosion developing.

Also, pipework to pipe support materials may differ and cause galvanic corrosion at the contact interface.

6 Temperature effects Ambient temperature differentials induce forces in process pipework and pipe supports. These forces are normally induced over a long period; however, the forces occur quicker if the thermal variations are affected by the contents of the process pipework changing rapidly, for example, during plant shutdowns and start-ups.

Lifting process pipework When coating breakdown or build-up of corrosion products under pipe supports is suspected Operators must decide whether to lift the pipework or deploy advanced NDT at the contact point areas.

Pipework has often been lifted in such situations as it facilitates a full external visual inspection round the circumference of the pipework and access for coating repair, debris removal and cleaning.

Isolation material can also be installed between the pipework and support to prevent galvanic corrosion.

However, lifting is viewed as an intrusive inspection method that often requires the process to be suspended and the plant being shutdown during lifting, venting and de-pressurising operations. The unknown condition of the process pipework prior to lifting also introduces a higher risk of a safety or environmental incident. For example, movement of the process pipework may dislodge corrosion products that were forming a plug/seal around a weak point which results in a pressure release and loss of containment. Damaged pipework may also not return to its original laydown location which could facilitate the need for repairs and unplanned shutdown activity.

Given the potential safety and environmental hazards of lifting process pipework, as well as the cost element of shutting down production, a number of non-intrusive methods have been

Inspecting corrosion under process pipe supports poses a number of major challenges. devised to identify loss of integrity through CUS.

Advanced NDT techniques and technology 6 Non-intrusive Ultrasonic (UT) ‘pitch and catch’ The ‘pitch and catch’ method, utilised by Stork across its international inspection operations, uses

S12 ORA 1 2012 Technology 01_Layout 1 09/02/2012 12:22 Page 51

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 64,000 people and operate a network of more than 1,250 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.

Technology

S12 ORA 1 2012 Technology 01_Layout 1 09/02/2012 12:22 Page 52

two shear wave probes; one a transmitter and the other a receiver; which are located in a carriage frame to ensure correct positioning for scanning.

The ultrasonic beam is applied in a circumferential direction (transmitting probe) in the pipework, the transmitted beam is received (by the receiving probe). Prior to carrying out the shear wave probe scanning, the technician confirms the process pipework wall thickness using a 0° compression probe. The compression wave scanning allows the technician to assess the coating / surface condition suitability for ultrasonic testing.

The operator sets the sensitivity settings locally to the test site. The carriage is then traversed over the test site (pipework to pipe support contact point area). The operator monitors the response signal and if there is none or a negligible reduction in response signal, this indicates there is no defect and loss of wall thickness. A reduction in response

A number of non-intrusive methods have been devised to identify loss of integrity through CUS.

signal amplitude caused by attenuation or beam scatter may indicate a defect or loss of wall thickness.

The resulting response signal amplitude can be used to calculate the residual wall thickness.

The system can use standard digital or analogue ‘A scan’ ultrasonic testing instruments and uses battery operated equipment meaning it normally only requires a “hot work category 2” permit. The system is flexible and can be used by multi-skilled rope access technicians, which negates the need for expensive scaffolding and can also impact on ongoing production operations. The system has a proven tracked record of testing from 1.0” to 42.0” diameters and has no minimum thickness limit.

6 Electro-magnetic acoustic transducer (EMAT) System.

Electromagnetic acoustic transducers transmit UT waves in materials without the need of a coupling medium (couplant). The EMAT system transmits “lamb” waves around the circumference of the process pipework and the probes are secured in a motor driven carriage with an encoder to track its location.

EMAT probes can penetrate most coatings and light corrosion and be used to test process pipework from 4.0” to 24.0” diameter. The system can detect both internal and external corrosion and be used on carbon steel and high alloy stainless

steels.

However, EMAT testing requires a consistent surface and access to the full pipe run for positioning and operation only provides qualitative information on the severity of the corrosion.

6 Multi-skip Multi-skip (M-Skip) is a type of advanced ultrasonic testing which uses time of flight diffraction (ToFD) principle. M-Skip uses two shear wave probes and the waves produced are transmitted through the material via multiple reflections from the front and back wall interfaces.

Computer software is used to measure the sound travel time between the two probes. This provides the average residual wall thickness along the ultrasonic beam between the probes.

Multi-skip has no upper limit for pipework diameter testing and can be utilised by rope access technicians. The computer generated reports can be analysed and audited off-site after inspection programme is completed and third party verification is required to confirm the results.

However, the system has a minimum diameter of 6.0” lower limit and the minimum wall thickness that can be resolved is 10.0mm. ■

* Les Colman, operations manager – specialist services, Stork Technical Services (previously RBG Limited)

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S12 ORA 1 2012 Technology 01_Layout 1 09/02/2012 12:22 Page 53

SAPREF CONTRACTED A local NDT company to carry out long-range ultrasonic testing (LRUT) on sections of the terminal process pipework to highlight possible areas of wall thickness loss. Once it was established that there were possible defect sites, Stork was contracted to participate in a two week trial to inspect these areas using its nonintrusive UT ‘pitch and catch’ technology.

The trial consisted of testing areas of pipework selected by SAPREF’s refinery inspection project team. The nominated areas had

been highlighted during the LRUT inspection as suspect and 90% of the suspect areas were at carbon steel process pipework support point locations ranging in diamater from 3.0” to 14.0”.

The trial test results were assessed and confirmed by: 6 Conventional radiography where access allowed.

6 Visual inspection by lifting of the lines.

6 Removing sections through cutting and welding operations.

The successful two week trial resulted in the award of an additional one year inspection programme at the refinery. Technicians from both companies utilised the advanced inspection technology to accurately assess, inspect and repair CUS at locations throughout the refinery.

During this one-year period up to forty pipe support joints, measuring in thickness from 3mm to 35mm, were accurately inspected per shift, providing SAPREF with significant time, cost and efficiency benefits compared with alternative inspection technologies, such as EMAT inspection systems.

Conclusion

The ‘pitch and catch’ method, utilised by Stork, is a cost-effective method of identifying CUS.

CUS is one the most common causes of loss of integrity of process pipework and it is crucial that Operators can quickly assess, inspect and repair areas of corrosion. While the lifting of process pipework has been carried out previously, advanced NDT inspection techniques, such as the non-intrusive UT ‘pitch and catch’ method are more commonly used due to the reduced safety, environmental and cost impact. The versatile technology allowed high levels of quality inspection to be carried out efficiently and cost-effectively at SAPREF’s refinery.

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Oil Review Africa Issue One 2012 53

Technology

Case study – CUS inspection at SAPREF refinery

Technology

S13 ORA 1 2012 Technology 02_Layout 1 09/02/2012 12:03 Page 54

Water as a by-product of oil & gas reservoir production has always been an inconvenience for oil & gas companies. However, as Graeme Murray of Oil Plus tells Vaughan O’Grady, legislation regulating its treatment and disposal is making produced water a much more serious — and expensive — problem.

Produced water: the billion dollar

clean-up Drilling engineers wish to avoid drilling direct into water zones.

M

UCH OF THE more recent oil and gas production in Africa — certainly the newer offshore exploration in subSaharan Africa — does not have a major problem with produced water. However, Ghana and other new arrivals will eventually face the same challenge as northern neighbours like Libya and Algeria and much of Nigeria: dealing with water coming up from wells as a by-product of production.

That is because the volume of water tends to grow over time. Graeme Murray, Global Sales Manager of Oil Plus, which provides independent consultancy services to the oil and gas industry, says: “The period of time you get dry [water-free] oil can be anything from a few minutes to a couple of years, but it's usually in the small number of months.” In Ghana, for example, where commercial production started in December, water can be expected in the first half of this year — but how fast the volume of water will grow is not easy to predict.

“Oil Plus has dealt with commercial wells that have 99.5 per cent water cut,” says Murray. As he points out these tend to be quite old but it is possible to reach that level faster if geology and other circumstances are not favourable. However, he says, “most operating companies are working at around 60/70 per cent water”.

Many major oil-producing assets that were early production sites when Oil Plus first offered its services over 30 years ago are now maturing or coming to the end of their expected lifespan. This, of course, means that the company has access to useful historical data when advising on the challenges these older fields may throw up. However, one challenge has little to do with the distant past.

54 Oil Review Africa Issue One 2012

As Murray says: “Many articles you read now, and presentations you go to, say that produced water is becoming more and more important. It's always been important. What is changing is the tightening of the disposal regulations. In the old days if you were onshore you threw your water onto the ground.

Treatment facilities need to be part of the platform or FPSO. What you should have done is dug a shallow pit, lined it so nothing would leak out of it and put the water in there. The water would evaporate, leaving behind whatever oil was left — and sand and chemicals and general ‘crud’.” Offshore, of course, it often went straight into the sea.

While high water cut makes oil production difficult, the water itself is not what is bothering legislators. The water arrives on the surface with hydrocarbons of course, but also with the chemicals that went into the system — biocides and corrosion inhibitors, for example — as well as, possibly, naturally occurring radioactive material (NORM).

“NORM are radioactive minerals that come up in the water as scale — typically combined with barium and strontium salts,” says Murray. Onshore in particular there is a risk of distributing all these environmentally harmful materials when the water dries, the residual material mixes with sand and the result may be blown over a wider area.

Legislation both onshore and offshore But legislation applies both onshore and offshore.

“Nowadays,” says Murray, “whether you are throwing it on the land or overboard, you have to meet the discharge regulations put in place by the legislators, and you therefore have to clean the water to some extent.” Pumping the water back underground into a rock formation that is loosely consolidated is an option — and one that involves less cleaning. More useful — but requiring more cleaning — is injecting it in or around the reservoir to help with oil production.

Murray explains: “In some reservoirs for every barrel of water you inject into the reservoir you get an extra barrel of oil out. In others it’s 70 barrels in for one barrel out. The economics can vary dramatically — but it helps.”

If you are onshore, the water will be cleaned at treatment plants — but the same need applies offshore, so treatment facilities will be part of the platform or the floating production, storage and offloading unit (FPSO). And this is not something you can put off for a year or two. As Murray point outs, “If you say that you will be cutting water after a year, the lead time to get the produced water system might be two to three years. So you do it right at the beginning. If you're building an offshore platform or an FPSO, you will design in the water treatment system straight away. The cost of adding it later would be probably 30 to 50 times greater.”

However, you also need to analyse the water properly, which is where Oil Plus comes in. “We go out and investigate what is being produced. We take lots of water samples at different times so we know what quality a treatment system has to deal with day-to-day,” says Murray.

S13 ORA 1 2012 Technology 02_Layout 1 09/02/2012 12:03 Page 55

Technology

S13 ORA 1 2012 Technology 02_Layout 1 09/02/2012 12:03 Page 56

Ghana and other new arrivals will eventually face the challenge of dealing with water coming up from wells as a by-product of production.

And the cleaner the water, the more heavily concentrated the impurities.

Oil Plus consultants can also advise on limits and how to meet them. Say there are 1,000 parts per million of oil in produced water that a client wishes to dispose of overboard. “If you have a rule saying you can only put in 20 parts per million oil in water into the sea, that’s what the treatment plant has got to get down to. We will tell them what equipment they will need to get from the 1,000 down to the 20.”

And the cleaner the water, the more heavily concentrated the impurities. “Instead of having it dispersed in millions of gallons of water, you’ve got a

few ‘bucketfuls’ of it — but you’ve still got to dispose of that properly,” says Murray.

As for disposing of the water after treatment, approaches in Africa vary from country to country. In Libya, for example, the NOC limited surface disposal in 2003; today produced water reinjection is the norm. Angola, by contrast, uses a mixture of produced water reinjection and disposal overboard.

Nigeria is a rather unusual case: there are not many produced water reinjection schemes there because the support aquifer that provides the pressure for many oil fields is massive “and,” Murray says, “in 50 years of development the pressure within some reservoirs has hardly fallen at all”. Thus, because they have no need to inject it into the reservoir to keep the pressure up, companies can treat the water and dispose of it overboard or on land.

Legislation constantly tightening Treatment technology has so far been able to respond to legislation. But legislation is constantly tightening. For instance, says Murray, hydrocyclones [which classify, separate or sort particles in a liquid suspension] are good at removing oil droplets or sand particles. “But that’s for, say, an output level of 30 parts per million. If the legislation then says 20, or even lower, you need to add some more process equipment after the hydrocyclones.”

Cleaning water to this level isn’t easy — even with newer technologies like membrane filtration, reverse osmosis and nanofiltration. Another factor is cost. Membrane filtration has been around for some time but is only just beginning to be used offshore. This is not only because there is a requirement for it but also because the price of oil

has gone up, making it an affordable method.

Inevitably, as legislation tightens further and if oil prices permit, newer technologies will come in — if they can be made commercially available.

This may soon become an urgent requirement, because treatment is not cheap. Nearly two years ago, the OTM Consulting/Douglas-Westwood Offshore Produced Water Gamechanger Report 2010-2014 estimated a treatment market worth approximately US$480mn a year and a re-injection market to be around $1,700mn a year, a staggering figure, but partly explained by the high capital expenditure involved in implementing re-injection on any production facility.

Higher oil prices will help to pay for produced water treatment but, ironically, they may also encourage production policies that make treatment necessary. After all, if higher prices can help to pay for more comprehensive treatment they also justify EOR, especially as an alternative, to establishing new fields way offshore where production costs multiply long before oil is produced. Put simply, 30 per cent is no longer the economic limit on recoverable oil. Thus, as Murray put its “there’s a huge number of fields that have got 70 per cent of their original oil still there. And companies are going back to look at these.” And, by definition, EOR will involve older fields, which will mean more produced water and more treatment.

That may not be relevant to Ghana, Uganda, Madagascar, Kenya or any of Africa’s newer fields at the moment. But high world demand, tightening legislation and the high cost of delay mean that even in these areas oil and gas producers will have to be ready from the start. ■

Unitech Offshore uses Hardide coating to enable subsea connector design A NEW LOW friction, non-porous, wear-resistant tungsten carbide coating from Hardide Coatings has enabled Unitech Offshore AS to design a unique ROV-operated subsea high-pressure connector with integrated ball valve for use in critical production applications including wellhead control, gas lift and chemical injection.

The UH-500 connector integrates a 2” reduced bore ball valve into Unitech’s standard UH-550 2” male stab connector resulting in an extremely compact and short assembly. Opening and closing of the ball valve at full working pressure of 10,000 psi is by a handle mechanism operated by the ROV manipulator while the ROV remains connected to the female connector with its class 4 torque tool.

The connector is now in use for customers including Cameron and BP on the latter’s Block 31 field in Angola.

Uwe Bauersfeld, general manager, Unitech Germany GmbH

56 Oil Review Africa Issue One 2012

The connector is now in use on BP’s Block 31 in Angola.

commented: “An extremely low friction, non-porous coating with superior wear resistance and a smooth surface finish was required for the ball and sealing cartridges.

Hardide-T provided a cost effective solution that could meet the challenging conditions in which the

UH-550 connector operates and we now have more than 120 units in the field.”

Bruce Robinson, chief operating officer of Hardide plc said: “Hardide provides enabling metal coatings that combine wear, erosion and corrosion resistant properties and

open up new engineering design opportunities for severe service applications such as high pressure, abrasive, erosive and sour environments. With Unitech, we were able to help them design this unique subsea connector and solve a specific end-user need.”

Hardide Coatings has developed a range of tungsten carbide-based precision coatings which offer an unprecedented combination of ultrahardness, toughness, low friction and chemical resistance when applied to components made from ferrous and nickel-based alloys.

They can coat internal surfaces and complex shapes and offer significant technical and environmental advantages over traditional coating technologies such as hard chrome and HVOF. The coating is in use by customers around the world in severe service applications in industries including oil and gas downhole and drilling tools, aerospace, valves, power generation, chemicals and food manufacturing.

S13 ORA 1 2012 Technology 02_Layout 1 09/02/2012 12:03 Page 57

S14 ORA 1 2012 Technology 03_Layout 1 09/02/2012 12:01 Page 58

Environment

Scientists from a UK laboratory have analysed over 4,000 air, soil and water samples collected from Ogoniland in the south of Nigeria.*

Lab analysis demonstrates severity

of Ogoniland pollution T

HE RESULTS OF the analyses, which were undertaken by ALcontrol Laboratories, have formed a major component of an independent UNEP Environmental Assessment report that sought to measure the extent of the pollution and to define priorities for remediation.

The UNEP report was published in August 2011 and shows that pollution from over 50 years of oil operations in the region has penetrated further and deeper than many may have supposed. It suggested that the environmental restoration of Ogoniland could prove to be the world's most wide-ranging and long term oil clean-up exercise ever undertaken if contaminated drinking water, land, creeks and important ecosystems such as mangroves are to be brought back to full, productive health.

Ogoniland is a group of four Local Government Areas in the Rivers State of Nigeria.

Taken together there are close to a million people living in about 1,000 sq km. Oil industry operations began in Ogoniland in the late 1950's and the area has since been the subject of many (often tragic) struggles as a result of the political and environmental issues that have occurred.

A complex study The two year study of the environmental and public health impacts of oil contamination in Ogoniland is one of the most complex on the ground assessments ever undertaken by UNEP. Conducted at the request of the Federal Government of Nigeria, the work involved desk review, fieldwork and laboratory analysis. As a high profile, politically sensitive project it was extremely important for all environmental analysis to be undertaken by a fully accredited, independent laboratory.

Environmental sampling and analysis Following an international competitive bidding process, ALcontrol was chosen to conduct the environmental monitoring work. ALcontrol's Iain Swinton was responsible for the bid and believes

The two year study in Ogoniland is one of the most complex on the ground assessments ever undertaken

by UNEP. 58 Oil Review Africa Issue One 2012

that his company's success was the result of several key factors. "Firstly, we were obviously able to provide a financially attractive offer, but importantly," he added, "we were also able to demonstrate a very strong track record in the delivery of a large contract, with a requirement for multiple parameter monitoring at remote locations with difficult access. For example, in the recent past we have conducted sampling and analysis programmes in Lebanon, Gaza, Mongolia, Ukraine, Afghanistan and Iraq."

With over 2,000 employees in 30 laboratories across 11 European countries supporting a global customer base providing millions of tests per year, ALcontrol is able to offer an enormous variety of tests. ALcontrol's laboratory in Chester, UK, was chosen to analyse the Ogoniland samples because, as a very large ISO 17025 accredited laboratory, it has the capacity to manage a project of this size and complexity.

The analytes examined in the study included those which are commonly required in oil-spill assessment and clean-up work. They included specific groups of hydrocarbons that are either indicative of oil based pollution or represent a significant human health or environmental hazard. The most important of these are BTEX (benzene, toluene, ethylbenzene and xylenes) and PAHs (polycyclic aromatic hydrocarbons). Volatile organic compounds (VOCs) were the main target of the air quality investigations. Over the course of the project more than 400 different analytes were tested, however, the most significant was TPH (Total Petroleum Hydrocarbon, mg/kg).

Collected samples were dispatched by courier from Nigeria on a daily basis and analytical results had to be published via the @mis web based reporting tool in the shortest possible time.

In some instances, additional sampling had to be undertaken based on the results of the first round, whilst in other cases repeat analyses were requested to reconfirm the findings.

In order to ensure that the study produced representative and credible results, ALcontrol was involved throughout the planning and implementation stages of the study. This included developing sampling protocols, sample preservation techniques, chain of custody procedures and analytical quality control techniques.

A dedicated team A dedicated team of ALcontrol scientists was established to manage the environmental monitoring component of the Ogoniland project.

The ability to review results over the web was a key benefit for this project.

This helped to ensure that the Nigerian samples were processed quickly but independently of the other work in the ALcontrol laboratory, which was important because the very high levels of contamination in many of the samples necessitated extra pre-analysis procedures. The provision of a dedicated team also improved communications and meant that ALcontrol was able to provide technical support by people that were familiar with the project.

The lead scientist for site services was ALcontrol's Geraint Williams who visited Ogoniland several times during the project and was responsible for the quality of sampling. He provided training on site investigation techniques, sample handling and chain of custody processes, and established suitable packaging, sample protection and logistics in order to ensure that samples arrived in Chester in perfect condition.

He also took a number of control samples to make sure that the sampling and transportation programme did not affect the results.

Detailed soil and groundwater contamination investigations were conducted at 69 sites, which ranged in size from 1,300 sq m to 79 hectares.

Each of the 4,000 samples was tested for multiple species. This included water taken from 142 groundwater monitoring wells drilled specifically for the study and soil extracted from 780 boreholes.

Looking back, Geraint believes that the ability to review results over the web was a key benefit for this project. "Ogoniland pollution is a highly

S14 ORA 1 2012 Technology 03_Layout 1 09/02/2012 12:01 Page 59

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Environment

S14 ORA 1 2012 Technology 03_Layout 1 09/02/2012 12:01 Page 60

Key findings

Environment ogoniland faces devas tating environmental pollution

sensitive issue and prior to the publication of the final report, the analytical results were confidential, so the data was posted to a secure website running the @mis reporting tool," he explained. "This avoided the necessity for using unsecure email, but the main advantage was the availability of almost live data 24/7, which was important because senior UNEP staff and their consultants were located in different parts of the world."

Typically, the time taken from sampling to the availability of result via the @mis system was ten days. Geraint says "It was very important for this to be kept as short as possible because of the tight timescales for the whole project, so it was vital for the consultants, that were responsible for the interpretation of the data, to have access to the results as quickly as possible."

There were a number of occasions in which it became necessary to determine the age and origin of a spill, so further specialist analytical work was necessary and senior members of the project team worked closely with ALcontrol staff to draw appropriate conclusions from the observed results.

The report was subjected to a rigorous international independent expert peer review to ensure that the work, including sampling protocols and quality control procedures, was fit for purpose. The report was finally published on 4th August 2011.

Soil pollution by petroleum hydrocarbons in Ogoniland is extensive in land areas, sediments and swampland. Most of the contamination is from crude oil although contamination by refined product was found at three locations.

Some areas, which appear unaffected at the surface, were found to be heavily contaminated underground. In 49 cases, hydrocarbons were detected in soil at depths of at least 5m. This finding has major implications for the type of remediation required.

The drinking water in at least 10 Ogoni communities is contaminated with high levels of hydrocarbons, posing a significant threat to public health. In one community, at Nisisioken Ogale, in western Ogoniland, drinking water is contaminated with benzene at levels over 900 times the World Health Organization guideline value. In one area, an 8 cm layer of refined oil was discovered floating on the groundwater which serves drinking wells. This was reportedly linked to an oil spill which occurred more than six years ago.

Volatile hydrocarbons, including benzene, were also detected in the air and mangrove vegetation has been severely impacted by oil slicks in the bay.

UNEP has recommended a series of technical, legal and institutional measures to restore the environmental situation in Ogoniland and estimates that it will take up to three decades and cost billions of dollars. UNEP has also recommended the creation of a new Ogoniland Environmental Restoration Authority and an Ogoniland Environmental Restoration Fund with an initial invest of one billion US dollars to initiate the clean up and restoration.

Reactions to the report Following receipt of the UNEP report President Goodluck Jonathan is reported to have constituted a committee to review its findings

and the oil companies operating in Nigeria have constituted a committee for the ’Restoration of Ogoniland to its old glory.’ It is anticipated that a transition project, leading to full scale clean up, will commence in 2012.

Following publication of the report, the Government of Rivers State has started providing clean drinking water to the communities whose water wells were demonstrated to be contaminated with carcinogenic substances.

SPDC Managing Director Mutiu Sunmonu has responded to the UNEP report in a video on the Shell Nigeria website. He says: “This report makes a valuable contribution towards improving understanding of the issue of oil spills and the environment in Ogoniland and we pledge to work with the government, UNEP and others on the next steps."

Commenting on behalf of ALcontrol, Iain Swinton said "We were very pleased to have been able to provide an important component of the UNEP report and we hope that it will mark the beginning of an effective remedial plan for Ogoniland.

“Environmental testing and monitoring forms an essential component of effective remediation, so with the lessons that we have learned from our involvement to date, I hope that we will be invited to participate further in the future.

“Our ability to publish 'live' results on the web was an invaluable tool in the UNEP assessment. However, @mis also gives us the ability to provide transparent environmental data to communities, which can be a useful tool in politically sensitive projects. " * ALcontrol provides testing and analytical services for soil, water, food, oil, asbestos and air to help clients demonstrate compliance with regulations and achieve their health, safety and environmental goals. ■ For further information on ALcontrol's full range of testing and analytical services, please visit www.alcontrol.com

New deep-water pipeline concept reduces cost but not safety DNV HAS DEVELOPED a new pipeline concept, called X-Stream, that can significantly reduce the cost of a deep- and ultra-deepwater gas pipeline while still complying with the strictest safety and integrity regime. X-Stream is based on established and field-proven technologies which have been innovatively arranged.

X-Stream can reduce both the pipeline wall thickness and time spent on welding and installation compared to deep-water gas pipelines currently in operation. The exact reduction in the wall thickness depends on the water depth, pipe diameter and actual pipeline profile. Typically, for a gas pipeline in water depths of 2,500 m, the wall thickness reduction can be 25 to 30 per cent compared to traditional designs.

“It’s essential for DNV that the new concept meets the strict requirements of the existing safety and integrity regime, and I’m pleased to confirm that this concept does,” says Dr. Henrik O. Madsen, DNV’s CEO. Current deep-water gas pipelines have thick walls and, due to quality and safety requirements, the number of pipe mills capable of producing the pipe is limited.

When installing pipelines, the heavy weights are difficult to handle and the thick walls are challenging to weld. And finally, the number of pipe-laying vessels for deep-water pipelines is limited too. New offshore oil and gas fields are being developed in deeper and deeper waters and export solutions for the gas are

60 Oil Review Africa Issue One 2012

critical. New exploration activities are also heading for ultra-deepwaters. The distance to shore is increasing too. The X-Stream concept can for such fields represent an alternative to e.g. floating LNG plants combined with LNG shuttle tankers.

By controlling the pressure differential between the pipeline’s external and internal pressures at all times, the amount of steel and thickness of the pipe wall can be reduced by as much as 25-30 per cent - or even more compared to today’s practice and depending on the actual project and its parameters. This will of course make it easier and cheaper to manufacture and install the pipeline.

“By utilising an inverted High Pressure Protection System – i-HIPPS – and inverted Double Block and Bleed valves – i-DBB – the system immediately and effectively isolates the deep-water pipe if the pressure starts to fall. In this way, the internal pipeline pressure is maintained above a critical level for any length of time,” explains Asle Venås, DNV’s Global Pipeline Director.

The new concept is simple and reliable. During installation, it is necessary to fully or partially flood the pipeline to control its differential pressure. During operation, the i-HIPPS and i-DBB systems ensure that the pipeline’s internal pressure can never drop below the collapse pressure – plus a safety margin. In sum – a certain minimum pressure will be maintained in the pipeline at all times.

S14 ORA 1 2012 Technology 03_Layout 1 09/02/2012 12:01 Page 61

Safety and Security

S15 ORA 1 2012 Safety Security_Layout 1 09/02/2012 11:59 Page 62

Oil bunkering through sabotaged pipelines form the main commercial risk to onshore oil majors. There are also rising incidents of offshore attacks. Hannah Waddilove and Rory Lamrock* look at the risks and challenges.

Oil bunkering: a growing commercial and

security challenge O

IL BUNKERING IS big business in the Niger Delta and the Gulf of Guinea.

Extensive sabotage to Nigeria’s onshore pipelines, compounded by hijacking of ships in Niger Delta waterways and the territorial waters of other West African states, arguably make oil theft the primary commercial and security concern for oil companies operating in the region. A 2011 report by the Maritime Industry Advocacy Initiative (MIAI) stated that Nigeria loses up to US$25bn annually in oil-bunkering, amounting to around 600,000 bpd. Offshore, 11 tankers were successfully hijacked in 2011, compared with none reported in 2010. As the ambition of criminal networks grows, and political militancy remains low in the Niger Delta, kidnap for ransom cases are also moving increasingly offshore.

Niger Delta governance Oil bunkering through sabotaged pipelines form the main commercial risk to onshore oil majors; in line with historical trends, Nigeria’s oilfields fail to operate at full capacity. While a fragile peace holds in the Niger Delta and political militancy has not resurged since the government’s two-pronged approach of military force and amnesty in 2009, the closure of the amnesty scheme in June 2011 led to an expected surge of attacks on oil infrastructure in the Niger Delta. While political militants have not re-grouped, the swathes of unemployed youth, trying to eke out a living and no longer in line for job training and amnesty stipends, are increasingly frustrated and now form a ready pool of recruits for criminal networks.

Although no hard evidence has come to light, criminal groups in the Delta are reportedly made stronger by support from local politicians and military personnel, who aide the lucrative oilbunkering business through supplying boats and getaway routes. With such powerful local brokers, investigations into oil bunkering, like the motion tabled by the House of Representatives in November 2011, will continue to be deflected. While the Nigerian Joint Task Force – a collection of different security agencies – have made recent gains in busting major oilbunkering rings, criminal networks operating in an environment of lax security will continue to flourish amidst the Niger Delta’s protracted governance crisis. With the fuel subsidy now removed, more than doubling the price of fuel overnight, there may be a significant increase in oil bunkering and illegal refining as black market demand for affordable fuel soars.

62 Oil Review Africa Issue One 2012

Smoke and flames billow from a burning oil pipeline in Nigeria.

Oil bunkering through sabotaged pipelines form the main commercial risk to onshore oil majors.

Onshore costs Despite oil production levels stabilising since the political militancy peak, operating costs for oil majors with pipelines in the Delta remain high.

Incidents of force majeure for example, particularly affecting the consortium Shell Petroleum Development Company (SPDC), rose in 2011. In most instances, sabotage attempts to pipelines are to blame. Resultant oil spills present dangerous and costly operating conditions, affecting production, exports and sometimes causing explosions. The high security risk posed by pipeline sabotage also raises costs as oil companies will be forced to step up efforts to protect infrastructure. Nigeria’s military

forces are stretched thin at the moment. Boko Haram violence is intensifying in the country’s north, and despite the government’s substantial security allocation in the 2012 budget, the Niger Delta is only a periodic headache for the Federal Government. The low-intensity, simmering conflict in the Niger Delta means that uninterrupted production in the oilfields cannot be guaranteed without further investment in security measures by oil majors. The stakes are also high for employment in the Niger Delta, thus despite oil company initiatives to employ locals to guard infrastructure, the capacity to protect hundreds of metres of pipelines is currently absent, and the local political will to do so is not always present.

Offshore hijacks Oil bunkering through sabotaging pipelines inland is caused by insecurity and unemployment, but largely presents a commercial problem to oil majors. The rising incidents of offshore attacks however, also related to criminal networks involved in fuel bunkering, increasingly presents a major

S15 ORA 1 2012 Safety Security_Layout 1 09/02/2012 11:59 Page 63

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Safety and Security

S15 ORA 1 2012 Safety Security_Layout 1 09/02/2012 11:59 Page 64

security challenge to the energy industry.

Attacks offshore, within the Niger Delta’s waterways and in the larger Gulf of Guinea, largely take three forms – low-level armed robbery, hijacking vessels at sea and kidnapping crew members for ransom. Most incidents of armed robbery occur at ports and anchorages; they are mostly opportunistic, driven by general criminality, and can be disrupted by crew alertness, watch rotas and basic security procedures. Vessel hijackings and kidnaps, however, are inextricably linked to the larger criminal business of fuel bunkering. Criminals engaged in bunkering often have an in-depth knowledge of the oil industry and attacks are therefore targeted and organised, posing serious security concerns to foreign energy personnel and assets.

There is plenty of evidence to suggest that attacks are well planned, financed and targeted.

Hijackings of tankers within the Niger Delta waterways and in the wider Gulf of Guinea are driven by the commercial and criminal motive of offloading crude or refined products. Unlike their Somali counterparts, pirates operating off West Africa do not hijack tankers to hold whole crews hostage in return for millions of dollars in ransom.

Rather, tankers are taken for the purposes of offloading as much cargo as possible before releasing the vessel and the crew. Hijack periods are normally limited to around 10 days, in contrast to detention periods in Somalia which average over 160 days. This kind of piracy is, by its nature, organised. Such large-scale involvement in fuel bunkering, particularly affecting ship-to-ship

90 per cent of the oil spills in the Ogoniland region of Nigeria's Niger Delta were caused by oil bunkering and theft.

transfers, would imply tacit involvement of officials in Nigeria as the infrastructure must be in place to offload significant quantities of fuel which is then sold on at other regional ports in the export market.

The frequency of hijackings increased considerably in 2011, with 11 tankers successfully hijacked in the Gulf of Guinea. In August 2011, after a spike of attempted attacks in June and July, Lloyd’s Joint Market Association extended the war risk zone from Nigeria to include Benin’s territorial waters, reflecting the increased area of piracy risk. In 2012 attacks are expected to continue to spread as increased navy patrols in traditional hot spots of Nigeria, Benin and Togo push piracy to waters previously considered safe.

Stationary or slow moving vessels will face increased risk, particularly those carrying out STS operations. Operators are advised to train crewmembers and ensure risk mitigation procedures are in place, and well-rehearsed.

Kidnap for ransom Targeting foreigners, namely oil workers, in kidnap for ransom operations is a by-product of the general

There are many alleged cases of oil bunkering and operation of illegal refineries in the Niger Delta region.

64 Oil Review Africa Issue One 2012

insecurity created, in part, by oil bunkering. In the last two years, kidnaps affecting the energy industry have changed shape: firstly, they are largely fuelled by criminality rather than through the overt political activity of Delta groups and secondly, they are increasingly instigated at sea, rather than onshore. A spike in incidents of kidnaps offshore for the purposes of holding selected crew members onshore indicates growing ambition among criminal networks, and a move towards maritime activity as a preferred tactic. In the last quarter of 2011, five attacks were registered on oil and gas supply vessels servicing Chevron and Exxon fields off Bayelsa and Akwa Ibom states, with four foreigners and one local held ashore for periods of up to 15 days before release.

There is plenty of evidence to suggest that attacks are well planned, financed and targeted.

Militants are generally well equipped with fast vessels and weapons, thanks to proceeds from ransoms and bunkering, and have a thorough knowledge of the energy industry often gained from insiders. Commonly, only selected foreign crew members will be taken from a vessel; anecdotal accounts recall attackers possessing lists of crew names when they boarded. Numerous smaller local vessels are attacked on a daily basis which may not impact directly on foreign energy companies, but reports suggest fishing vessels are increasingly hijacked to be used as motherships in order to strike further offshore. The attack on MV Endeavour on 17 November at Chevron’s Agbami field 70NM offshore demonstrated that pirates can operate significant distances from the coast, and kidnaps are no longer confined to coastal areas.

The uncoordinated international response on anti-piracy measures, compounded by the limited capacity of West Africa navies and lax security in the Niger Delta, indicate that companies will be faced with these operational risks for the foreseeable future. ■

*Hannah Waddilove and Rory Lamrock are intelligence analysts at AKE Group, an international risk mitigation company. For more information on political and security risks in sub-Saharan Africa, please contact hannah.waddilove@akegroup.com .

For more information on piracy and maritime security please contact rory.lamrock@akegroup.com

S16 ORA 1 2012 Alduco_Layout 1 09/02/2012 12:52 Page 65

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Technology

Cathodic protection solutions for corrosion control and life extension of offshore oil and gas infrastructure. Alfredo Jones* looks at some of the new technologies available.

Cathodic protection solutions:

A 21st century approach T

HE HIGH COST of replacing depleted anodes on ageing and new offshore oil and gas structures, has led to a poor maintenance culture, in other words not replacing the depleted anodes, by some owners of these facilities. The consequences of not having adequate cathodic protection on offshore structures is that their integrity is compromised, which could in turn have catastrophic effects. The mindset of some asset owners is “Don’t fix it till it’s broken”. The danger with this is that by the time it is broken, it might be too late. This paper deals with new and innovative cathodic protection technology that is helping to change the mindset of these operators; it is innovative, eliminates the risk of structure integrity failures due to corrosion, and is easy to install, with cost savings in some cases as much as 80 per cent, to the conventional way of changing anodes.

The integrity of many offshore oil & gas structures including; fixed platforms, FPSOs, pipelines etc can be compromised either because of their age or because they are subjected to hostile, corrosive marine environments and their cathodic protection systems have become depleted or damaged, hence the structures are no longer protected from corrosion. Offshore structures require continuous and adequate cathodic protection to ensure prolonged and safe operations.

The major consequences of structures without adequate cathodic protection are that; the owners would be in breach of their host countries’ and their countries’ laws, the structural integrity of the facility could be compromised by leaks due to corrosion and pollution of the environment.

Even with the knowledge of the abovementioned consequences of not maintaining the integrity of offshore oil & gas structures, there are still a lot of facilities out there operating without adequate corrosion prevention systems in place.

Installation of a Retropod.

66 Oil Review Africa Issue One 2012

How does corrosion occur on offshore structures? The corrosion of metals occurs because the metals interact with the environments. In the case of steel, man has mined iron ore and processed it into steel. However due to certain characteristics of the steel, it is not ‘stable’ once in contact with an aqueous environment and reacts in an attempt to return to its naturally occurring state, corrosion occurs.

Cathodic Protection (CP) Cathodic protection is a method of corrosion control that is used to protect submerged facilities like offshore oil and gas structures. This process is either by galvanic (sometimes called sacrificial) anode or an impressed current anode with power supplied into an immersed corrosion circuit. There is a direct current (DC) flow from the anode to overcome the natural DC current that flows from the offshore steel facility into the seawater during the corrosion process; this causes the corrosion to cease.

The conventional method of corrosion prevention is the use of sacrificial anodes attached to new structures during fabrication or just before they are put erected in the sea. This is easy to do and is cost effective as the corrosion prevention solution is either welded or bolted on before the structure is put in place.

There are still a lot of facilities out there operating without adequate corrosion prevention systems in place.

The conventional approach to anode replacement, when the CP system has reached the end of its design life, is to replace anodes on a one for one basis, this approach is completely unnecessary as it adds additional weight to an already old structure - it’s very costly, complicated and dangerous for divers; in some deepwater cases impossible i.e. divers cannot reach below certain depth to attach replacement anodes.

Deepwater Corrosion Services Inc, a global leader in the provision of corrosion control solutions, recognised the high costs, logistics and health, safety and environment concerns involved, in replacing depleted cathodic Protection systems (anodes) on offshore structures and have developed a series of “non-weld” retrofit options for replacing depleted conventional anodes that include galvanic (sacrificial) anodes and impressed current cathodic protection systems that cut down on cost, reduce

Structure attachment (Called RetroClamp)

installation time and that can be installed at depths that cannot be reached by divers.

The hardware consists generally of three main elements: 1. Anode Retrofit(s) - Anode retrofits may be galvanic or impressed current. Figure. 1 shows a typical galvanic retrofit system RetroPod which is made up of aluminum anodes arranged in stable, self-contained 'pods' and rests on the seabed. The benefits of the Retropod is that you are not adding any additional weight to the structure as it is deployed at a short distance from the facility but still protects the whole structure.

2. Interconnect Cables - These are the cables that connect the anode to the structure, so they have to be designed to perform long term. Fortunately they are generally very corrosion resistant and being on the cathodic half of the circuit receive the benefit of full time cathodic protection.

3. Attachment to Structure - The structure attachment is the most critical element. Mechanical connections are the most cost effective, and also the speediest to install. The attachment clamp that has been successfully used on a number of projects is shown in Figure. 2. The clamp can be installed both by divers or ROV. This new innovative & cost effective solution of carrying out cathodic protection retrofits has been tested and proven to work and is fast replacing the conventional methods. It can be found on facilities of leading oil and gas companies worldwide. ■ * Alfredo Jones, Managing Director of Alduco Energy a company that specialises in Corrosion management services to the oil & gas industry in the Gulf of Guinea.

S16 ORA 1 2012 Alduco_Layout 1 09/02/2012 14:12 Page 67

S17 ORA 1 2012 Rig refurbishment_Layout 1 09/02/2012 11:27 Page 68

Technology

Africa’s rig count is on the rise as drillers target new oil and gas frontiers

Drillers in

determined mood W

ITH MORE RIGS plying their trade in Africa at the start of this year, the outlook appears promising early on in 2012 for drillers and

contractors.

Recent oil and gas finds offshore, and growing appetite for onshore work, have also sparked renewed interest in new parts of the continent.

According to data from leading industry providers, rig utilisation rates across West Africa have tightened significantly during the past 12 months.

The fleet utilisation rate for rigs in the West Africa region - the number of rigs in the area under contract, relative to those not currently in use stood at 83.3 per cent, at the end of January 2012, according to the IHS Petrodata Rig Count.

Twelve months earlier the fleet utilisation figure stood at 71.9 per cent.

Significantly, the fleet of rigs in the area has also grown during the same period, rising from 64 a year ago, to 72 at the start of this year.

Safety concerns will also be front of mind, however, after a Chevron rig caught fire off Nigeria at the start of the year, an incident that claimed the lives of two foreign workers.

The shallow-water jack-up, KS Endeavor, which was under contract to Chevron but operated by FODE Drilling Nigeria Ltd, was drilling a gas exploration well some 10 km off the coast in approximately 12 metre water depths.

The cause of the incident remains under investigation, but it will have no doubt been an unwelcome wake up call to the industry and all its many hazards.

Exploration in deepwater environments such as West Africa, among others, has buoyed demand for rigs able to handle such tough conditions.

Industry upbeat The rig utilisation trend broadly matches that seen in most other hydrocarbon producing regions around the world, such as the Middle East, Australia and the Mediterranean, where fleet utilisation has also tightened.

68 Oil Review Africa Issue One 2012

Fairstar’s open stern, semi-submersible vessel Fjell Offshore is to transport the jack-up drilling rig Hercules 185 to West Africa.

It’s a sentiment echoed by industry executives from rig contractors and associated service providers, as the climate for drilling hots up, despite the relative economic gloom in Europe and certain other parts of the world.

At the turn of the year, Fairstar Heavy Transport announced that it had won a US$2.6mn contract to haul a rig back across the Atlantic to West Africa from the US Gulf of Mexico.

The company’s heavy transport vessel, Fjell, will carry the Hercules 185 rig to Angola, after it was brought to the US just last year from the West Africa region.

The company’s other heavy transport vessel, Fjord, is also working in the West Africa region early this year, discharging the Oando rig, Respect, then setting sail to Angola to load the CLOV floating production storage and offloading (FPSO) vessel.

As well as hauling the Hercules 185 rig, the Fjell is also engaged on a job to transport Agrium fertiliser plant modules to Nigeria.

“Fleet utilisation for 2012 continues to improve,” Philip Adkins, Fairstar`s chief executive commented.

Supply and demand Seadrill chief executive Alf Thorkildsen also said last year that exploration in deepwater environments such as West Africa, among others,

has buoyed demand for rigs able to handle such tough conditions.

The discovery of oil and gas in new deepwater territories such as Ghana, Tanzania and Mozambique had further boosted the need for these rigs, he said.

And he added that stricter rules after the Deepwater Horizon explosion in the Gulf of Mexico have also spurred interest in newer platforms, boosting prices in this segment.

As a consequence, rig rates for the ultradeepwater market in particular are rising.

When rig supplier Atwood Oceanics announced its fourth quarter results at the tail-end of last year, its president and chief executive Rob Saltiel called 2011 one of the most successful year’s in the company’s history.

He cited the delivery and start-up of Atwood’s first ultra-deepwater rig, expansion of its high-spec rig construction programme, and growth in its contract revenue backlog.

“We also achieved our sixth consecutive year of record earnings," he said.

Investment in new rigs is always a sign of a healthy market, with Atwood ordering another ultra-deepwater drillship the month before, with delivery set for 2014.

But investment in new rig supply is also being hampered by tough financing conditions, as a result

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Technology

Look east

The semisubmersible drilling rig West Leo from Seadrill has a one-year contract with Tullow Oil Ghana Ltd.

of the rather subdued global economic mood, particularly in debt-ridden Europe.

More drilling is expected in deepwater Tanzania and Mozambique this year.

Frontier drilling It is not just big oil producers like Nigeria and Angola pulling in the investment either. Other key locations and established producers, such as Congo and Gabon, are hosting multiple rigs.

Bowleven, in December, lined up the Atwood Oceanics rig, the Atwood Aurora, for drilling services work in Cameroon, starting this May, for a period of around four months.

But other frontier West African hotspots have come to prominence too.

Transocean’s ultra-deepwater Discoverer Spirit drillship, for example, is currently under contract to Chevron for work in Liberia, after recently working for Anadarko Petroleum off Sierra Leone at the end of last year.

And contract rates are holding firm with the offshore rig company - the world’s largest deepwater driller - netting rates of $564,000 per day for the Liberian work.

These emerging locations have opened up since the discovery of vast oil deposits in Ghana, including the large Jubilee field, which is now in production.

Transocean also has a semi-submersible rig, the Sedco Energy, working off Ghana for Tullow on a job that will run until late 2012, with a value of $440,000 per day.

And a high spec jack-up, the GSF Monitor, is booked in for drilling a well off the Ivory Coast in the middle of this year, on behalf of Rialto Energy.

The picture looks promising going forward too

70 Oil Review Africa Issue One 2012

with operators lining up rigs far in advance.

Equatorial Guinea looks set to see plenty of activity after US-based oil company Hess hired Seadrill for an 18-month slot starting in the second quarter of 2013.

For Seadrill, the eight-well contract has a potential value of $127mn.

It will be the first assignment for the West Esperanza rig, which Seadrill ordered in June 2011, and which is currently under construction at the Keppel FELS yard in Singapore.

Transocean’s ultra-deepwater Discoverer Spirit drillship is currently under contract to Chevron for work in Liberia. A view of its derrick.

And with more drilling expected in areas outside of West Africa there is every reason for contractors to remain bullish about the year ahead.

This includes the fast emerging frontier waters of East Africa, where drillers have unearthed a succession of huge gas finds in the past couple of years.

As well as further and more intensive exploration work, this will also now prompt appraisal drilling in the area, as operators seek to monetise any discoveries.

More drilling is expected in deepwater Tanzania and Mozambique this year, where companies such as BG Group and Anadarko Petroleum are stepping up the pace of activity following their recent offshore successes.

Anadarko has taken on another Transocean ultra deepwater drillship, Deepwater Millennium, for work offshore Mozambique this year.

The company is looking to take a lead in this emerging offshore zone and convert its gas finds into major export projects.

Within a few years, it could turn Mozambique already a key pipeline gas supplier to South Africa into a global liquefied natural gas (LNG) exporter.

Onshore excitement It has also triggered further interest across the rest of the region onshore, in neighbouring Kenya, for instance.

Uganda’s known oil deposits have served to suck in greater interest and investment in recent years as well.

This includes other parts of Uganda, especially in and around the highly prospective Lake Albert region, bordering the Democratic Republic of Congo (DRC), and also across the border in previously less fashionable onshore destinations such as Kenya.

Uganda pioneer Tullow Oil and Canada’s Africa Oil Corporation have begun drilling an exploratory well in northern Kenya, for instance.

The Ngamia-1 well on block 10BB, in the Lokichar basin, part of the East African Rift System, is the first by the partnership, which is hoping any find could trigger another drilling rush akin to that in Uganda in recent times.

"Our Ngamia prospect could be a play opener for another great success in the region," Keith Hill, Africa Oil president and CEO said, citing Tullow's exploration success in Uganda’s Lake Albert Rift Basin.”

Africa Oil also started exploratory drilling on the Dharoor valley prospect in neighbouring Somalia's semi-autonomous Puntland region, the first to be sunk in the country since civil war erupted two decades ago.

Onshore Tanzania has also witnessed greater activity, in terms of drilling and new concession activity, partly as a result of the recent deepwater discoveries offshore and because of the country’s proven shallow water gas deposits.

These fields are now producing gas for power generation and industrial facilities onshore.

It means plenty of work for drillers to bid for and not just in the traditional hot spots of West Africa, but this time right across the continent. ■

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Vandrezzer e is one of Nigeria's firrst indigenous Engineeering, Procurement, Co onstruction and Installation n companies that has developed in in-ccountry capabilities to handle Turnkey EPCI projects in n the country's Oil and Gas sectorr. Her experrtise spans from Conceeptual studies, FEED and Detailed Engineering D Design; through Procurement, Fabrication & Installation of Pipelines, Production facilities and Wellhead Jackets in n Onshore and Offshore locations.

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Nigeria

Oil Review Africa interviews SAPETRO’s CEO, Martin Trachsel on his expectations for 2012.

Growing African independent:

SAPETRO W

E ARE SO pleased to be able to speak with you and would like you to give us a recap of your activities in 2011.

2011 was a memorable year for SAPETRO. Production continued from Akpo where we also progressed with preparations for the Egina field development project. In Benin we completed the FEED for the SEME field redevelopment and, in December, took the decision to proceed with the project. Tendering is currently being fast-tracked.

We also progressed exploration studies and will be getting ready for our first exploration well in Benin Block 1.

In the Mozambique Channel, we ended the year with two exciting and adjacent frontier exploration blocks. ‘Non Opposition’ from the French Government to the acquisition of a 75 per cent interest in the Juan de Nova concession was received in October 2011 whilst Government approval for the Madagascar Belo Profond block was received in December 2011.

These two new country entries and the decision to commence development operations in Benin makes the year one of the most exciting after achieving first production in deepwater Nigerian acreage in 2009. On the last day of the year we also commenced acquisition of 2D seismic in our Juan de Nova permit.

committed to a fast track re-development which will give us first oil in 2013. In the Mozambique Channel, we signed an agreement with PGS and are currently shooting 12,000km of 2D seismic. Finally, we shall continue to support social responsibility initiatives including those that we commenced in previous years in Nigeria and Benin.

We also want to look beyond our home country to other areas of the continent where we see significant opportunities that we can exploit.

You have mentioned Nigeria a couple of times so far. Why not invest there?

We are intending to make a huge investment in Nigeria in the Egina deepwater field. We also want to look beyond our home country to other areas of the continent where we see significant opportunities that we can exploit. This is why we have the slogan Africa Is Our Home. In this context, investing in East Africa makes great sense. Following the recent Anadarko and Eni discoveries of up to 60 tcf of gas, the area is a very exciting place to be right now.

What does 2012 have in store for SAPETRO? 2012 will be another big year for SAPETRO. Production will continue at plateau rate of 175,000 bpd from the Akpo field in our OML 130 concession. In the same block we are aiming, in conjunction with our partners Total, Petrobras and CNOOC, to launch the multi-billion dollar Egina project. The importance of this to Nigeria cannot be overstated as it will take Nigerian content to new levels and generate new local capabilities.

In Benin, we shall progress the tender for surface and subsurface systems and services. We are

74 Oil Review Africa Issue One 2012

This sounds like a hectic year. Does this rule out any new acquisitions?

We never rule out new acquisitions!

Sèmè field in the Republic of Benin is SAPETRO’s first field as operator. What are the main challenges that you have faced?

Every challenge is an opportunity. As you say, Sèmè is our first field as operator and we have had to grow accordingly as an organisation through the recruitment and integration of new staff. Also the relative isolation of the Sèmè field means that we have additional expenditure in comparison, say, to a Nigerian field where we could tie in to neighbouring fields. But there are many factors in our favour: it is a brownfield with known remaining reserves, the terms are reasonable and the country is politically stable.

The fact that we are operating in a different geopolitical climate has allowed our Nigerian staff to gain experience of working in a new environment and benefit from that.

Considering the size and water depth of your Block 1 in Benin, what made you decide to invest in Juan de Nova and Belo Profond, which are considerably larger acreages in deeper water?

Sèmè has provided us with the best possible opportunity to expand our field development capabilities. Block 1 in which Sèmè is located is 551 sq km, which is admittedly very small indeed compared to the combined acreage is 67,000 sq

Left to right: Uzoma Echegiri, GM SAPETRO; Bonaventure Rasoainaivo, DG OMNIS; Jacques Radilofe, MAREX INC at the signing of agreements for the Belo Profond block in Antananarivo, Madagascar.

km for our Mozambique Channel blocks! In deciding to invest in the Mozambique Channel assets, we ascertained that we needed some high impact high reward exploration assets to supplement our non operated production in Nigeria and our own development operations in Benin. In the process, we reviewed some interesting opportunities within Africa. Some were licensing opportunities while some entailed farm in and/or complete acquisitions. The Juan de Nova and Belo Profond assets fitted our criteria with reasonable entry terms and huge upside.

Hence, we negotiated and today, here we are.

But is SAPETRO technically capable of developing an asset in such deep water?

We are currently acquiring over 12,000 km of state-of-the-art broadband 2D PGS Geostreamer/Geosource seismic survey and a simultaneous campaign to sample and analyse surface hydrocarbon seeps utilising Gore C5-C35 technology. Within 18 months of assuming operatorship we expect to have a portfolio of seismically and geochemically supported prospects for 3-D detailing and drilling in one of the world’s major emerging hydrocarbon provinces. We will seek partners with superior technical expertise. We have been partners with major multinationals in OML 130 for over 13 years and we have seen firsthand the benefits of collaboration. We will leverage greatly on the lessons learned from our OML 130 projects in our Mozambique Channel acreages. ■

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Full Steam Ahead for

Vyacheslav Tikhonov

SMNG

SMNG operates the newest and largest 3D seismic vessel in Russian geophysical industry Newly-built 3D seismic vessel, owned by Polarcus and chartered by Russian shipping company Sovcomflot (SCF) under a 5-year Bareboat Charter Agreement with a purchase option of the vessel commencing after the third year of the Agreement, has got her new name, Vyacheslav Tikhonov, during the naming ceremony, held on 16 September 2011 in the Russian Black sea city of Sochi.

Vyacheslav Tikhonov is an ultra-modern 3D seismic vessel designed to work worldwide in the most challenging offshore areas, including environmentally vulnerable Polar regions, and capable of deploying up to 8 streamers each of 6 000 m length or 6 streamers each of 8 000 m length.

JSC Sevmorneftegeofizika (SMNG) will provide seismic operatorship and marketing services for the vessel. Vyacheslav Tikhonov is currently working on her first 3D project for Rosneft and ExxonMobil on the Tuapse Trough of the Black Sea. The vessel is to acquire 4800 sq. km and expected to complete the survey by April 2012.

SMNG, Russian largest marine geophysical company, provides a wide range of geophysical services, including marine seismic data acquisition, data processing and integrated seismic data interpretation.

SMNG owns a specialized fleet of five vessels capable of shooting 2D/3D surveys worldwide both in deep and shallow waters.

The Company’s head office is in Murmansk, Russia.

For more information, visit www.smnggeophysics.com

Tel: +7 (8152) 45 07 43 ischenko@smng.murmansk.ru

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Technology

Refinery and process plant operations can be improved with correct application and understanding of plate heat exchangers (PHEs). Chikezie Nwaoha discusses.

Improving refinery and

process plant operations A

PLATE HEAT exchanger (PHE) is an important piece of equipment commonly used in refineries and plants. It was invented by Dr Richard Seligman in 1923 and soon revolutionised methods of indirect heating and cooling of fluids without the usage of electricity. Also called plate and frame heat exchanger, it functions by simply transferring heat from one fluid to another through the use of metal plates. Comparing it with other conventional heat exchangers such as shell and tube heat exchanger or spiral heat exchanger, the PHE is favoured mainly because the fluids work on larger surface areas and are capable of dispersing on the metal plates, thus greatly increases the speed of the temperature change. It has a compact size and could easily fit in narrow spaces in a plant.

In a PHE, the fluid flows through a series of walls of alternating chambers usually made of stainless steel having high thermal conductivity to facilitate the interchange. Stainless steel plates are preferred because it has the ability to withstand corrosion and high temperature and is noted for its durability and strength. The plates are usually thin in depth, separated at their largest surface by a corrugated metal plate. Making each chamber thin ensures that the majority of the volume of the liquid contacts the plate, hence aiding the heat exchange. The plate design ensures that turbulent flow is maintained within the PHE. The plates are arranged with precision together and between them sealing gaskets are placed to contain the fluid within the system.

All plate heat exchangers look similar on the outside. The difference lies on the inside, in the details of the plate design, plate arrangements, the number of path and the sealing technologies used.

Some PHE are covered with insulation to prevent heat and energy escape.

Numerous advantages PHE has numerous advantages compared to other heat exchangers. It is always preferred due to its compactness, flexibility and ease of cleaning. Its compactness can be attributed to the fact that this unit operation does not require a large floor space.

Its flexibility is seen with its ability to cope with requirements of different types of fluids. The plates are removable thus making it easy to clean. If replacement is needed, the plates may be removed conveniently as well. The PHE can also be sized up or down. It is just a matter of adding or reducing the corrugated metal plates.

Normally, there will be a container underneath

76 Oil Review Africa Issue One 2012

the PHE to contain fluid in case of leaking. Leaking may occur due to several reasons but is always possible to avoid preventive steps are taken. The container will prevent fluid from spreading in the plant floor and provide some time before operators can rectify the PHE problem.

The earliest PHE was constructed from cast gunmetal plates and enclosed within a frame, which become the standard for today’s more advanced PHEs fabricated by various companies worldwide.

Today’s PHE is definitely more effective and efficient after several years of improvements. There have been more in depth studies and improvements on the plate corrugation patterns, plate arrangements, sealing technology and others.

Companies like APV, Schmidt-Bretten, Graham and Alfa Laval have set such high standards.

PHE has numerous advantages compared to other heat exchangers.

Example of a plate heat exchange.

engineer needs to consider the piping connections for the newly installed PHE in an existing plant. For a new plant, normally, a dedicated location has been allocated for the PHE. Bear in mind to ask the manufacturer to design the PHE based on your requirement but with room for sizing expansion.

Selection strategies

Comparison with other heat exchangers

We need to know the fluid flow, temperature, pressure of both cool and hot fluid passing through the PHE. The important data we can obtain here is the temperature change in the PHE. A process engineer should also identify the cost of the PHE as well as the cost of equipment (pressure gauges, valves, RTD etc), parts for PHE installation.

For a new engineer, there’s nothing to be worried about. If you are not sure what kind of data to provide on the initial planning, just contact the PHE manufacturer and they will normally have a design questionnaire for you to fill up based on your process and application or simply ask you a series of questions. Just answer the questionnaire or questions and the PHE manufacturer will soon provide you with the most appropriate PHE design for your process. Part of the information that needs to be answered will be the details of fluids in your process which are crucially imperative and affect the PHE design. Hence, you need to know the type/name of fluid, specific gravity, specific heat, thermal conductivity and viscosity. Based on my experience, the PHE manufacturers normally have the physical data of fluids their clients run in the plant.

Besides that, for an existing plant, a suitable space/area should be carefully selected. A process

A PHE is a very compact equipment that can provide efficient heat exchange compared to other heat exchangers such as shell and tube or spiral heat exchanger. For a similar amount of heat exchanged, the size of PHE is smaller due to the large heat transfer area provided by the plates. A significant plus point for a PHE is the fact that the heat transfer area can be scaled up and down easily via controlling the amount of plates.

However, a PHE using a gasket has a limited operating temperature. It can only go up to the maximum temperature the gasket can withstand.

Beyond that, the gasket may not be capable of tolerating the high fluid temperature. The shell and tube on the other hand can go to higher temperatures compared to PHE mainly because of its gasket capability and all tubes inside it are welded - spiral wound gasket made of stainless steel can hold higher temperatures and pressures.

A PHE can easily be dismantled for cleaning, maintenance and replacement of the plates. A shell and tube heat exchanger cleaning normally needs cleaning-in-place (CIP) before being applied with high pressure jet water pump. Occasionally, the corner point of the shell and tube heat exchanger is the toughest one to be cleaned and cleared. A spiral heat exchanger on the other hand can only

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ISISAN GERMANY - Frankfurt/Germany ISISAN GULF - Dubai/UAE ISISAN AFRICA - Alger/ALGERIA ISISAN INDIA - Mumbai/INDIA ISISAN ISTANBUL - Istanbul/TURKEY ISISAN Head Office and Factory O.S.B. 21. Cad. No:6 38070 - Kayseri/TURKEY Tel: +90.352.321 13 43 Fax: +90.352.321 14 13 info@isisan.com.tr

Technology

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be cleaned via CIP only. There’s no way of it to be dismantled as it is constructed in such a way like a spiral. Each layer of stainless steel is welded and thus if there is a tiny leak, the spiral heat exchanger could not be used anymore.

Best practices There are a few best practices that have been applied. Among them is to make a preventive maintenance schedule. By doing this we can stop the PHE at certain time and let the process run on a standby PHE. CIP can be conducted if the scale or fouling is not too bad. A CIP need to be carried out in a proper way and the engineer in charge should design a suitable standard operating procedure (SOP) especially for the PHE CIP. Otherwise, a major maintenance service must be carried out which is to dismantle the plates and clean them and then reinstall the clean plates into the PHE. Another point is to take the inlet and outlet temperature and pressure as well as the flow rate reading of the PHE. This needs to be done consistently on a daily basis. From this exercise, an engineer or supervisor can monitor the trend of temperature drop and detect whenever the PHE performance is deteriorating. For relatively advanced monitoring, a process engineer can calculate the U-value (overall heat transfer coefficient) of the PHE and assess the performance of the PHE based on it. To make it more interesting, this data can be captured from the PLC/SCADA; programme and formulate it and make the U-value appear in the SCADA. Supervisors and plant operators can easily detect the lack of performance when they notice the U-value of any operating PHE is not up to certain value. An alarm or indicator can also be installed to make notification automatic, instant and efficient. As soon as the engineer and his team identified an underperforming PHE, he or she can assess and instruct the PHE to undergo CIP or plate replacement. If there is other maintenance work to be carried out, it also can be done at that time.

Following are the best practices that I proposed: 6 Install proper RTD and PT before and after the PHE for both hot and cold fluid. Monitor them regularly.

6 If possible, connect them to PLC or SCADA for

Plates are arranged piece by piece after fixing the clip on the gasket.

fast and continuous monitoring.

6 Formulate and programme the U-value to enable

6 6

6 6

6

6

6

6

6

6

immediate identification of which PHE is deteriorating in terms of performance.

Schedule a preventive maintenance to service the PHE and stick to the schedule.

Regularly check and service the RTD and PT attached to the PHE to ensure correct and reliable readings.

Properly conduct CIP to get the effective and efficient result.

Prepare an SOP for CIP. Include pressure monitoring from the start of CIP until the end, suitable caustic or cleaning solution concentration, the right NPSH for the pump for CIP etc.

Always prepare a set of clean plates ready to be used when one PHE is stopped for plate replacement.

Stick or clip the gasket properly and calmly. If the gasket is not properly aligned or attached on the plate, it may be the source of leak when the PHE is already commissioned.

Install a filter before the PHE inlet to avoid contaminants, unidentified or unexpected object to enter and choke the PHE. Check the tie-bars periodically and tighten if needed. Consult the PHE design specification for this.

When designing a new PHE, base it on your process requirement but do not forget to consider upgrading.

Make insulation for the PHE.

Common pitfalls associated with PHE

Example of a plate heat exchanger with thermal insulation to discourage heat from escaping from the exchanger.

78 Oil Review Africa Issue One 2012

There are situations where the hot fluid and cold fluid flow rates are not balanced. This situation normally occurs during plant start up, plant shutting down or plant failure etc. When this occurs, the plate’s pressure will not be balanced and leaking can likely occur. The best way to overcome this is to have better control of both fluids’ flow rate. The flow rates need to be gradually slowed down together to avoid imbalance pressure within the plates.

Sometimes, pressure builds up in one side of the flow. One of the reasons is due to unexpected dirt or particles penetrating into the system and choking the PHE. To avoid this, install a filter/strainer before the PHE. This will help to block unexpected objects from entering the PHE and blocking the flow. Then, periodically check and

clean the filters/strainer.

Occasionally, leaking occurs due to the tie-bars not being tightened properly. Therefore, to avoid this, check plate tightening dimensions and the integrity of the frame, tie-bars, etc periodically.

Erosion of plates is another point of concern.

Though plates are normally made of stainless steel, there are situations where certain areas around the plate become thinner. As a consequence that particular area experiences pitting and results in leakages. Therefore, PHE operators/engineers need to identify this plate and replace it when it becomes thinner. Another way to prevent this is to avoid flow rate beyond the recommended limit.

Consult the PHE design specification for this data.

The PHE of tomorrow will have an improved gasket and as a result the PHE can withstand higher process temperatures.

Technical innovation and future plans PHEs already have good prospects in terms of the technology and application. They are very much in demand especially in narrow and small places.

However, I hope PHEs in future will have a more durable, tougher, safer and healthier gasket. The gasket must be able to withstand higher temperatures and pressures. Hence, I believe, the PHE of tomorrow will have an improved gasket and as a result the PHE can withstand higher process temperatures.

Plans for the future include making the PHE capable of tolerating high temperatures. This can be done by developing a stronger and more durable gasket. This is the challenge for materials and polymer engineers. PHE is already a brilliant piece of heat exchange device and because it depends very much on gaskets, it is the gaskets that need to be further improved. There are also issues of the safety and health of the gasket material. Gaskets made of asbestos can be dangerous for health.

Therefore, designing and creating a safer and healthier gasket is imperative. ■

Note: This article was culled from an interview with Zaki Yamani Zakaria (AMIChemE), Universiti Teknologi Malaysia.

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THE 4 TH SAUDI ARABIA INTERNATIONAL OIL & GAS EXHIBITION

24-26 SEPTEMBER 2012 DAMMAM, KINGDOM OF SAUDI ARABIA WWW.SAOGE.ORG

Technology

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A new generation of diverless subsea connectors has been developed by Aker Solutions, making the installation of subsea systems in deep water easier, faster and more reliable.

Staying

connected F

OR TODAY’S DEEPWATER offshore developments, far beyond the depth limits for divers to work underwater, sophisticated remotely operated tools are needed to interconnect subsea hardware on the seabed. A range of pipelines and pipework flowlines, jumpers and umbilicals – some of them rigid, some of them flexible, must be securely tied in to subsea wells, manifolds and other equipment.

“Making such connections safely and reliably, often thousands of feet below the sea surface, requires purpose-designed systems which can be operated by remotely operated vehicles,” explains Bård Kristiansen, Aker Solutions’ product and concept manager for subsea tie-ins and structures.

“As subsea developments have moved into ever deeper waters to access fields which frequently have higher operating pressures and temperatures, the tiein connection systems have grown in size and complexity, and installation costs have increased accordingly. This is why Aker Solutions set out a couple of years ago to develop a range of new subsea connectors which are lighter, easier to install and more cost effective, to meet the current and future needs of our clients.”

Many existing connection systems depend on large ‘running tools’ – mechanical/hydraulic devices which bring together the two sides of a connection before joining them. These are heavy, require large service vessels to transport the equipment to the offshore location, and more service hands to carry out the operations - altogether a slower and more costly process.

Aimed at overcoming such drawbacks, Aker Solutions has worked with several client companies, including oil companies and leading installation contractors, to develop a new generation of subsea connectors, which are already being used offshore.

Qualification testing and feedback from the client companies has ensured the connectors have been designed to meet client requirements, targeting cost effectiveness and reduced time offshore.

Many advantages over exisiting systems “The new connectors offer many advantages over existing systems,” says Kristiansen. “They are more compact and can be mobilised faster on smaller vessels by fewer service hands; the installation tools are lightweight and can be moved around subsea by standard work-class remotely operated vehicles (ROVs); no heavy running tools or additional external guiding are

80 Oil Review Africa Issue One 2012

Testing of the new vertical connection system at Tranby, Norway.

involved; there are no integral hydraulics built into the connectors; and the overall connection operations are much faster. We believe these are the most efficient connectors available.”

The basic procedure for using the connector to attach rigid or flexible pipes to subsea hardware on the seabed involves bringing together two ‘hubs’, one fixed as the termination at the end of the pipe, the other pre-installed on the subsea component.

The termination hub is first positioned or ‘landed’ on the component, an ROV uses a ‘stroking tool’ to draw the two hubs together, followed by a ‘torque tool’ to close the clamp around the two hubs and the metal seal between them. The seal is pressure tested by the ROV and the connection is complete.

The ROV moves on the next connection.

Two versions of the connection system have been developed by Aker Solutions, one for vertical connections (VCS) and one for horizontal connections (HCS). The connector design has been standardised for use in 3,650 m of water.

Internal operating pressure can be up to 10,000psi, although a 15,000psi design could be qualified if required; normal operating temperature design is up to 121ºC, but connector seals for 180ºC are also available.

The VCS is based around Aker Solution’s highly successful connector clamp technology which has notched up 1700 applications over the past twenty years. Among the many attractive features of the new VCS is the tolerance for a starting offset of ± 8 degrees between the two hubs for rigid spool installation (±15° for flexibles), which will subsequently become perfectly aligned when the clamp is closed. The connector is already being

installed offshore Ghana for the Jubilee field development, where 135 connectors of 168-324mm outside diameter will be installed during 2010.

“The VCS installations are proceeding very well, with positive feedback from the client,” notes Kristiansen. “And we already have further orders for the VCS for Brazil and the Gulf of Mexico. The intention is to build a portfolio of VCS sizes, up to 711mm outside diameter.”

The HCS is an evolution of Aker Solutions’ tried and tested guide and hinge-over system for horizontal connections, some 350 of which have been delivered to date. While a vertical connection is usually the preferred solution in the industry due to the relatively straightforward installation procedure, there are circumstances where horizontal connections are required – for example for flowlines pre-installed on the seabed, for low profile subsea systems in fishing zones, or where a subsea tree or manifold is to be retrieved to the surface without also retrieving the jumper.

Aker Solutions HCS has been designed to accommodate these and other requirements and a 305mm HCS is currently undergoing full scale testing at the company’s Tranby facility in Norway.

The plan is to have a range of HCS connectors up to 711 mm, although a 1059 mm connector is also in the early development stage.

Adding to the advantages of both VCS and HCS is the fact that the connection process is readily reversed – the connectors can be opened to allow seal replacement or hub cleaning, without employing a surface crane for assistance and without subsea hardware being brought back to the surface. ■

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Innovations

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New isolation valve SCHLUMBERGER HAS RELEASED the Fortress* isolation valve, which simplifies the transition from upper completion to production without the need for intervention.

“The Fortress isolation valve was designed based on field-proven experience and extensive testing related to debris accumulation,” said Mike Garding, president, Schlumberger Completions. “The new valve serves as a bidirectional barrier valve that exceeds ISO 28781 standards to the point of providing a bubble-tight barrier. This barrier enables increased safety, especially in applications such as deepwater where high differential pressure is required. The reduction or elimination of interventions translates to reduced costs and rig time saved while productivity is increased through the prevention of formation damage, and minimising fluid loss.”

The Fortress valve is designed for deepwater and other harsh environments where debris accumulates and actuation requires more force. The Fortress ball

does not have gaps or passageways that allow solids to accumulate in critical spaces, which would prevent the ball from rotating. Friction is reduced and the ball is allowed to open under higher differential pressures through the use of simplified cages, a simplified arm and wiper rings, which reduce the amount of solids that can enter the ball housing space.

The valve effectively minimises frictional effects and shifting force variability caused by debris. The valve also optimises the actuation energy available, allowing the valve to be operated in wells with high differential pressures of up to 4,500 psi across the ball.

A South American operator selected the Fortress isolation valve for use in a deepwater horizontal well. The valve was successfully installed at a water depth of 1.5 m in a deepwater horizontal openhole gravel pack completion. After 30 days of suspension time the valve was successfully remote-actuated from surface.

Double blockage facilitates pipeline replacement TD WILLLIAMSON HAS completed the first-ever subsea STOPPLE Train isolation. The patented STOPPLE Train plugging system links two plugging heads into a “train” capable of providing the added assurance of double block at each isolation point. The double isolation was performed in about 18 m of water in the Gulf of Mexico to facilitate abandonment and decommissioning of an old platform.

In the past, pipeline operators used a number of different methods to achieve double block functionality. These methods typically required more than one hot tap and fitting to achieve a double block, but the Stopple Train plugging system requires only one tap and fitting. Its linked plugging heads can be inserted into a line through just one opening. A single hot tap and fitting yields the double block benefit of two separate in-line plugs.

Double block was critical in this case. A platform was being abandoned, requiring the removal and replacement of a section of pipeline. The pipeline section came up as a riser, crossed the platform and returned down as a riser before continuing. Both of the risers and the platform section of the line needed to be removed.

The line was bled down to 0 psi, then two 30 cm Stopple Train systems were inserted – one on each side of the section to be removed – to prevent seawater, sand and organic debris from entering the hundred-mile line when the section of the pipeline was cut out.

“The Stopple Train system was ideal because the line in question was a non-piggable sales gas line,” says Calvin Schmidt, Senior Sales Representative for TDW. “It was very important not to flood the line. The dual seals of each Stopple Train plugging system ensured that the line was isolated and would not flood.”

Once the new piping was successfully installed, the seawater between the two plugging systems was evacuated and replaced with warm nitrogen to absorb and remove moisture. Following removal of the plugging heads, the pipeline was re-energized and placed back into service.

The STOPPLE Train plugging system was introduced in 2008. An initial wave of five plugging head sizes (4- through 12-inch) were specifically designed to cover about 80 per cent of hydrocarbon processing industry applications. In response to requests from pipeline operators who also sought the value of double block and bleed, a second wave of sizes (including 16- and 24-inch) has been tailored to cover about 80 percent of pipeline market needs. Additional sizes (20- and 30-inch) are due by year’s end. To date, more than 80 piping and pipeline isolation projects have been performed using the system.

82 Oil Review Africa Issue One 2012

Bits for challenging downhole conditions SMITH BITS HAS announced the introduction of its Kaldera advanced roller cone bits for geothermal and hightemperature drilling applications. Advanced materials technology has been developed to provide an engineered sealing and lubrication system for the drilling of high-temperature (HT) wells.

“High-temperature downhole environments, particularly those occurring in geothermal wells, pose a unique set of challenges for the roller cone drill bit,” said Guy Arrington, president, Bits & Advanced Technologies, Schlumberger. “A new range of advanced materials were developed, combined with an engineered design solution, to deliver improved bit performance in these applications. The Kaldera bits substantially increase onbottom hours, thereby reducing drilling costs in geothermal and HT wells.”

The seals are made from fabric reinforced fluoroelastomer composites providing thermal stability and wear resistance. An innovative grease compound was developed from synthetic base oils and functional additives to increase load capacity at elevated temperatures to ensure adequate lubricity of the bearing sealing system.

Field trials of the Kaldera bits demonstrated improvements in reliability over conventional roller cone drill bits. In a recent geothermal well in Italy, where temperatures can exceed 277°C, bits with the new sealing system were successfully run. A new field record was recorded, drilling 77 hours in a single run, marking a 37 per cent increase of on-bottom drilling hours when compared to offset runs. At the end of the run, all seals and bearings were graded as still effective.

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Innovations

Drilling technology results in huge savings AFTER ANALYSING CLIENT data from offset wells, the Baker Hughes drill bit team in Egypt developed a case for a trial run of the Hughes Christensen Quantec PDC bit technology, which resulted in savings of US$152,000 on two wells. After using both PDC and Tricone bits in demanding deep-drilling applications, Baker Hughes, operating as a joint venture with the Egyptian Government Petroleum Company, had found the Tricone bits delivered only slow rates of penetration (ROP).

After studying the formation characteristics, Tricone selection and failure of other PDC bits that had been used, company experts realised that they needed to increase durability without sacrificing ROP. “Working with the client to analyse offset data, Baker Hughes committed to trial bits to help the client reduce overall costs with bit selection to increase ROP and to realise longer bit runs,” said Mohamed Zanaty, technical marketing representative.

In the first well chosen for the test, the interbedded Alam El Bueib formation was drilled with an 8 ½-in. Quantec bit, replacing two tungsten carbide insert (TCI) bits from direct offsets. “The Quantec frame is stable, and the premium cutters are both durable and impact resistant, resulting in longer, faster runs,” said Darren Eckstrom, senior application engineer for Baker Hughes drill bits for Egypt, Syria and Jordan.

The heterogeneous Alam El Bueib formation is highly interbedded with abrasive intervals that go from hard to soft and vice versa, posing great challenges for PDC bits, Eckstrom adds. “There are often negative drill breaks and a very high probability of the onset of drilling dysfunctions such as stick-slip or whirl, which are destructive to PDC bits. Six-bladed, 16-mm cutter bits were tried, but they came up short because of durability and cutter breakage and were pulled for slow ROP.” With a high percentage of torque management, the Quantec bit drilled smoothly, handling the interbedded formations without bringing on drilling dysfunctions.

The results were 73 per cent higher ROP and 35 per cent lower cost per metre compared with recent offset wells, delivering cost savings of $71,000.

Effective solutions for extreme oil & gas challenges OIL AND GAS producers strive for increased equipment reliability and added service life. They demand operational and environmental safety, and they work to eliminate downtime, reduce maintenance and prevent losses. And they always look for ways to increase output. Dow Corning’s effective solutions for extreme conditions help them get these tough jobs done right.

Whether facing challenges on salty offshore platforms, in dusty oilfields, at safety-critical terminals or along high-pressure pipelines, oil and gas producers want proven solutions.

Molykote brand specialty lubricants and Dow Corning brand severe-duty sealants are designed to help solve critical problems that occur during

exploration and extraction, transport, storage, and processing.

Molykote brand Smart Lubrication solutions include severe-duty greases, anti-seize pastes, anti-friction coatings, and silicone oils and greases. These advanced formulations can help control friction and wear, reduce fretting corrosion and galling, extend lubrication intervals, and improve reliability.

Severe-duty silicone sealants from Dow Corning, including pastes, coatings, form-in place gasketing materials and hot-melt assembly adhesives, are suitable for equipment assembly, maintenance shop repairs and in-field service and are designed to meet the many challenges in oil and gas applications.

Oil Review Africa Issue One 2012 83

1Innovations

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Tullow joins subsea wellhead JIP TULLOW OIL HAS signed up as an additional consulting partner to a Joint Industry Project (JIP) to develop a new and safer subsea wellhead, using Plexus’ patented POS-GRIP technology.

Other partners include Maersk, Shell, Wintershall and SafeKick.

The new wellhead, designated the HGSS, will address technical issues and requirements highlighted by regulators following the Macondo incident in the Gulf of Mexico in April 2010.

The JIP partners will contribute to the design and engineering process with a view to becoming end-users once the wellhead has been fully built, tested and commercialised.

Plexus expects the project, launched in October, to take between 18-24 months to complete at a cost of US$2.3-3.1mn. The company will own any intellectual property generated.

Features that will be incorporated into the HGSS include: 6 18-3/4” full bore system, rated to 15,000 psi (1,034 bar), 350°F (176°C) 6 Upgradeable to 20,000 psi (1,379 bar), 450°F (232°C) 6 Four million-lb ‘instant’ casing hanger lockdown capacity 6 Avoidance of problems associated with use of lock down rings 6 Annulus monitoring and bleed-off capability to address sustained casing pressure situations, with diagnostic and remedial capability 6 Ability to open and reseal the casing annulus to facilitate remedial cement job procedures 6 Rigid metal annular seal technology qualified to match standards for premium casing couplings 6 Meeting the requirements of API 17D/ISO 13628-4.

New dive intervention craft RBG, THE LEADING provider of assess, inspect and repair (AIR) services to the global energy industry that was recently acquired by Stork Technical Services (STS), has enhanced its subsea service capability with the launch of two purpose-built dive intervention craft (IC).

The launch was announced by RBG’s new Marine & Subsea director, Roddy James. In his new role, Mr James is responsible for leading and growing RBG’s global marine & subsea activities, and identifying subsea project and contract opportunities that can utilise the skills, expertise and technology from across RBG & STS marine & subsea portfolios.

RBG has invested around US$3.1mn in the ICs which will support the delivery of specialist marine and subsea services, including subsea intervention, air and nitrox diving, survey and light ROV work, throughout RBG’s global operations. In the coming weeks, the ICs are being deployed for a number of integrated subsea IRM (inspection repair and maintenance) activities, both inshore and offshore. They are equipped with a range of advanced technology, such as a bespoke diver recovery system and software based dive management systems, that have been specifically designed to provide a safe operating environment for the divers and crew onboard.

The ICs offer a stand-alone shallow water diving solution up to depths of 50 metres and can operate at ranges up to 150 nautical miles offshore. The craft can also be launched by a bespoke davit system, from the RBG chartered Olympic Triton vessel, to allow continuous onsite diving which provides significant efficiency and logistical benefits to customers. The ICs provide a flexible alternative to dive support vessels for maintenance and survey activity, which often have restricted access to areas around rigs and FPSOs.

Corrosion-free fire safety deluge system replaces carbon steel pipework ELASTOPIPE, TRELLEBORG’S CORROSION-free fire safety deluge system, has replaced existing carbon steel pipework on Maersk’s FPSO vessel Ngujima-Yin. Two years after installation, the existing carbon steel seawater deluge system on the FPSO vessel Ngujima-Yin, working in the Vincent oil field off Western Australia, had corroded. The deluge system, which extinguishes fire by spraying large quantities of water, required constant maintenance, cleaning and testing, and a replacement was required to reduce the long-term cost of ensuring essential fire protection.

“Trelleborg provided the complete survey, design, engineering, supply and installation package, as well as removing the old installation,” explains Christian Eilersen, Director FPSO Projects, Maersk. “It was important that the operation of the FPSO was not affected in any way and that safety was considered to be of paramount importance. Trelleborg ensured not only a quick and effective, but also a safe installation.”

The challenge with the installation was to replace the existing fire protection throughout the seven FPSO modules without affecting the safety of the vessel

84 Oil Review Africa Issue One 2012

itself as it continued output. The system required 1,687 m of pipework, with diameters ranging from 25 to 200 mm, and associated fittings and accessories.

“Because Elastopipe is a synthetic rubber-based flexible piping system, it is installed without any welding or other hot work, such as high-speed cutting, which could compromise the safety of the vessel,” says Hans-Leo Hals, Elastopipe Product Group Manager, Trelleborg. “We installed a temporary Elastopipe deluge system for each module, removed the existing steel pipes, then completed the permanent Elastopipe pipework and fixings and moved the temporary deluge on to the next module. This method ensured that full fire protection was retained throughout the project.”

In addition, the flexibility and lightweight of Elastopipe allowed for a very rapid installation. Compared with a rigid pipe system it can swiftly be configured for confined spaces.

“The first two modules were completed in just a month, in contrast to the estimated 15 months [required] to install a comparable copper-nickel installation,” Hals said.

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Innovations

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Launch of intrinsically safe pipeline corrosion tool CORDEX INSTRUMENTS HAVE launched a new ultrasonic tool for detecting corrosion in pipelines which for the first time provides the ability to build a predictive maintenance programme to improve safety.

The intrinsically safe tool for non-destructive testing - the UT 5000 - has the ability to rapidly measure metal thickness to establish the extent of corrosion and is combined with intelligent data tracking.

The UT5000 with CorDEX CONNECT uses RFID technology to locate and log up to 1,000 measurements, each linked to a specific location, date and time. It can be used for days or weeks in the field before the data is downloaded, providing accurate corrosion analysis and helping to predict potential failures. A unique corrosion mode helps identify thinning spots and MultiECHO™ technology improves measurement accuracy on uneven surfaces.

The tool has been developed in response to integrity issues, particularly in ageing pipelines which can run for thousands of miles.

Calls have been made recently for an increase in fines following tragic pipeline incidents in the US where defective welds and poor testing and record keeping have been blamed.

Marcus Halliday, CorDEX Instruments Director said: “More than 2.5mn miles of pipeline deliver oil and gas to communities and businesses around the US alone. Multiply that many times around the world and it is clear that pipeline maintenance programmes based on solid information can save companies millions of dollars and avert dangerous failures. The UT5000 can safely and rapidly measure any corrosion and with its smart RFID technology, can build the robust report required to identify and trend developing trouble spots.”

Advanced reservoir characterisation technology BAKER HUGHES HAS introduced the next generation of its Reservoir Characterization eXplorer™ (RCX™) and In-situ Fluids eXplorer™ (IFX™) formation testing services.

Used jointly, these services accurately characterise fluid properties in real time—eliminating the need for extensive and time-consuming analyses.

Combined with other formation evaluation techniques, they provide critical information about a reservoir’s commercial viability.

The RCX service is designed for enhanced reliability in challenging highpressure, high-temperature wells. Its high-capacity pumps also improve operations in highly overbalanced wells. The service gathers comprehensive pressure data and representative fluid samples at up to 27,000 psi and 201°C. It is also compatible with the Baker Hughes multitank carrier module, which offers the largest volume, single-phase sample chambers in the industry—up to 28 chambers.

Designed primarily for deepwater and high-temperature wells, the IFX service characterises downhole fluid compositions in real time to allow robust fluid identification, to optimise sample collection and to provide input to the petrophysical evaluations for early assessments of a reservoir’s value. Unlike other technologies in the industry, the IFX service has a tuning fork sensor and separate sound speed transducer that provide high-resolution density and viscosity and sound speed information. This data allows the direct calculation of a continuous gas-oil ratio without reference to any offset information.

“The next generation of RCX and IFX are part of our flagship wireline suite of measurements. They push the pressure and temperature boundaries to provide our customers with critical information for decision-making in the well construction process,” says Scott Schmidt, president of drilling and evaluation for Baker Hughes.

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86 Oil Review Africa Issue One 2012

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IN COMPETITION WITH other service providers, Tube Tech International was awarded a three-year term contract by Nigeria LNG Limited (NLNG) following the success of a complex fast-track descaling operation at the company’s Bonny Island processing facility. Nigeria LNG Limited is jointly owned by Nigerian National Petroleum Corporation (49 per cent), Shell (25.6 per cent, Total LNG Nigeria Ltd (15 per cent) and Eni (10.4 per cent).

NLNG discovered that cooling water condensers tubes, heat exchangers and pipelines within their liquid natural gas plant had become severely contaminated by deposits, classified as uncleanable using traditional processes due to the small diameter and length of tubes.

Tube Tech organised an airborne assault – chartering three cargo aircraft to fly 32 multidiscipline operatives and 46 tonnes of specialised equipment from the company’s UK base – within only two weeks of the site visit.

Working continuous days and nights in often extreme weather, Tube Tech established the condition of each individual application. A combination of 12 innovative techniques was

used to clean and descale all straight and U-bend heat exchangers and pipelines, without cutting.

Tube Tech completed the cleaning and integrity inspection three times faster than the nearest competing estimate, saving millions of dollars in profits that would otherwise have been lost through extended downtime.

Bonny Island LNG processing facility.

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Innovations

Tube Tech performs impossible descaling task

Innovations

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Aubin launches offshore lifting system

Omega launches monitoring technology

AUBIN, A LEADING independent supplier of specialist chemicals to the energy industry, launched a new product that could save millions of dollars when installing offshore renewables infrastructure.

The Gel Lift System (GLS) offers the potential for significant cost savings and risk reduction in the critical installation phase of offshore renewables development.

The technology, which uses a novel low-density gel, can be used to install all types of offshore renewables including wind, wave and tidal. The gel which can be reused is non hazardous and environmentally responsible.

By reducing the specification and complexity of cranes and crane barges required during installation, GLS supports the use of more commonly available vessels generating savings typically in excess of US$150,000 per day, thereby accelerating the uptake of renewable technology development offshore.

The ability to promptly install and commission any renewable system once manufactured, significantly reduces yard/storage space requirements and the level of upfront investment required from developers.

Aubin, together with Aberdeen based engineering partner Ecosse Subsea, are currently developing installation techniques utilising GLS for offshore wind, wave and tidal technologies. Aubin’s GLS can support infrastructure weighing more than 1,000 tonnes and has an operational depth of 100 m, making it suitable for most European locations identified for potential renewables developments.

OMEGA WELL MONITORING, specialist in the manufacture and supply of downhole memory tools, has announced the launch of its latest product, the Leakator.

The tool, for which patents are pending, is optimised to locate leaks and monitor downhole flow. It has been developed in response to the increasing requirements of the industry to improve efficiency and reduce operating costs, by monitoring well integrity.

The Leakator’s run-it-yourself capability means an existing on-site crew can operate the tool without the need for further staff. It is easy to maintain. No moving parts mean that only the o-rings and detachable batteries need to be replaced during servicing. And as a result of its small AA batteries, operators do not need to comply with dangerous goods legislation during transportation.

This means operators can commit less time and staff to the job.

A modular memory instrument, the Leakator uses multiple sensor arrays, with synchronised data from the sensors merged and plotted against depth to highlight local variations in the well. This provides an indication of leaks. Optional sensor modules enable additional data to be monitored, including differential temperature, flow and flow direction. The sensors are physically distributed and have a balanced output, allowing extreme sensitivity to very small local anomalies of temperature and flow. A surface read out capability is also possible.

As a result of the modular assembly, operators can customise the set-up to fit the specific requirements of each individual job, determined by the various well conditions. And the Leakator’s 25mm diameter means it can access all zones.

Neil Matheson, managing director of Omega Well Monitoring, said: “The Leakator is a must have technology for oil and gas operators looking for improved well monitoring. Its ability to protect well integrity by detecting leaks, while also allowing operators to monitor flow and temperature will provide substantial benefits in terms of improving efficiency and enabling cost savings.”

Rotork is ‘one-stop actuation shop’ for storage tank expansion project ROTORK HAS DEMONSTRATED its ability as a one-stop shop for valve actuation products and services for an oil storage tank expansion project in Holland. Rotork’s activities have encompassed the supply of intelligent electric actuators for isolating, modulating and failsafe valves, digital control systems, valve gearboxes, valve adaptation, workshop motorisation, on-site Rotork is the global retrofitting and commissioning. leader in actuation.

Royal Vopak is the world’s largest independent provider of tank terminal capacity for the oil and chemical industries. An expansion project at the Vopak Oil Europoort Terminal has increased the total storage capacity by 160,000 cu m to approximately 3.5mn cu m, strengthening the company’s position as an independent bunker station in the Port of Rotterdam. Phase 8 of the project involved the construction of four new 40,000 cu m capacity fuel oil tanks, a pump pit with manifolds and an OCU (Odour Control Unit) which is the fourth to be installed on the site for environmental improvement.

Rotork is the holder of a valve actuation framework agreement with Vopak and has previously supplied more than 1500 actuators, the majority with Pakscan two-wire digital control systems, on the existing Vopak site. For Phase 8 Rotork has delivered a comprehensive range of products and services that illustrate many aspects of its group capabilities and closely match the technical and logistical demands of the project.

The bulk of the new valves, totalling 111 on-off installations, have been motorised with Rotork IQPro actuators. These are designed for robust reliability with enhanced functionality, featuring non-intrusive, intrinsically safe commissioning, data logging and predictive maintenance capabilities.

88 Oil Review Africa Issue One 2012

New subsea vibration suppression system launched POLYMER AND SYNTACTIC foambased solutions provider, Trelleborg Offshore, has launched T-Strake, a new vortex induced vibration (VIV) system.

"Pipelines unsupported over free spans, such as steel catenary risers and rigid steel flowlines, are prone to VIV fatigue, which can cause serious performance issues such as pipe girth weld failure or premature pipe malfunction," said James Vultaggio, vice president engineered products, Trelleborg Offshore. "To combat this, the TStrake comprises overlapping and interlocking moldings, with threestart helical strakes to provide an effective triangular or trapezoidal strake profile."

The system is temperature resistant up to 90°C/ 194°F and is available in a wide choice of

The T-Strake system is resistant to temperatures of up to 90°C

colours. Each section of the system has been designed as a single component, and this enables the system to be stacked during shipping, ensuring efficient transportation.

"The T-Strake was developed in response to market demand for a high quality, cost-effective VIV suppression solution,” said Austin Harbison, design engineering technologist, Trelleborg Offshore.

“We utilised an innovative manufacturing technique enabling rapid manufacture, reduced transportation costs and quick installation. Working with polymers across a number of technologies and industries, we were able to use our insight and innovation to improve VIV suppression performance using best-value engineered solutions."

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S19 ORA 1 2012 IT Feature_Layout 1 09/02/2012 11:22 Page 90

Satellite services do not all uniformly transmit and receive on the same part of the electromagnetic spectrum. In the second of three articles on satellite communications in oil and gas production, Vaughan O’Grady discusses the advantages and disadvantages of the various bands used by both fixed and mobile satellite services.

Satellite services:

battle of the bands F

OR THE OIL and gas industry, affordably taking Wi-Fi, WiMAX or cellular offshore or into remote areas is almost impossible.

Thus, while they may be relatively expensive, satellite links using very small aperture terminals (VSATs) are often the best option.

However, FSS (Fixed Satellite Services) VSATs are not the whole story. Smaller, more portable MSS (Mobile Satellite Services) terminals also play an important role in connecting remote oil installations, and the vessels that may serve them, to the rest of the world. And between them these services operate, or soon will be able to operate, on a number of bands in the electromagnetic spectrum. They are, in rising order of frequency range, L, C, Ku and Ka. Simon Curran, business development manager with Inmarsat, highlights the advantages of MSS — hardly surprising perhaps as Inmarsat’s BGAN (Broadband Global Area Network) is one of the bestknown examples. As Curran puts it: “BGAN is roughly the size of a laptop and the terminal is powerful enough to send large amounts of data and operate in the harshest of environments. The big advantage, however, is its capability to provide both reliable and simultaneous telephone services and high-speed data communications from a portable broadband device that fits in a backpack and can be set up in minutes.”

It is true, as he notes, that VSATs are more expensive and complex to use and install than BGAN, not to mention more power-hungry and much less portable. He adds: “Reliability can also be an issue as VSAT will generally work well in clear conditions but, unlike low-frequency satellite systems such as BGAN, it can be disrupted by heavy rain or dust storms.”

Of course proponents of VSATs might argue not just that they have greater power and capacity but that the L band used for Inmarsat’s BGAN services has drawbacks of its own. It may indeed suffer little or no atmospheric attenuation and use reliable, low cost technology but it also implies less and, therefore more expensive, bandwidth than other bands (VSATs tend to operate in the higher C and Ku bands). However, Inmarsat will soon be able to offer an alternative. “Our Inmarsat-5 Global Xpress network, due to be introduced in 2013, will be able to offer customers mobile broadband speeds of 50Mbps to terminals as small as 60cm,” says Curran. “It will be the first time a commercial operator has utilised Ka band radio frequencies to deliver a global satellite service.”

Global Express terminal design (and how

90 Oil Review Africa Issue One 2012

For the oil and gas industry VSATS are often the best option.

terminals will be supplied) is still to be decided. It is also not clear whether the offshore, or remotely sited, oil and gas industry will want to take advantage of the system and for what sort of applications. However, the potential advantages of the Ka band certainly compared to the L band in terms of capacity are an obvious attraction. Hence, Curran suggests, “Global Xpress will make intensive video monitoring of remote sites and infrastructure a cost-effective option for oil and gas companies.

For example, they could place cameras at regular intervals along the length of an oil or gas pipeline, using a relay point to maintain unbroken coverage of the installation over a single broadband connection.”

Ka band does have coverage limitations at the moment, not to mention problems with rain fade; heavy rain can diminish signal strength. However, if these challenges can be overcome Ka may not only benefit Global Express but VSATs too. Martin Jarrold, Chief of International Programme Development of the Global VSAT Forum (GVF)* points out that stabilised and ruggedised antennas are of smaller size in Ku band than in C band, and will be of smaller size still with Ka band, “thus reducing the physical footprint of the antenna in the context of potentially restricted deck space, particularly where satellite equipment is retro-fitted on, say, a drillship”, he points out.

But the enormous 2.4m VSATs served by C band won’t go away just yet. In offshore settings, on more advanced E&P sites such as semisubmersibles, you are likely to find stabilized 2.4m

VSATs — stabilised to compensate for the effects of waves on the vessel — operating on C band.

Given the sheer size of the VSATs involved, C band isn't easy to work with. However, the lower frequencies that C band uses perform better under adverse weather conditions than the Ku band or Ka band frequencies and, says Jarrold: “C band is still highly valued due to its inherent reliability in the offshore environment and global coverage.

Typically, deepwater offshore E&P sites utilise C band due to requirements to transfer larger amounts of data critical to operations reliably.”

However, lower cost, smaller Ku band equipment is making inroads into the E&P offshore market and, he says, “Ku band is approaching global coverage — and covers nearly all oil and gas hotspots — and is gaining a stronger reliability record.”

It’s a popular choice onshore too. “In land-based operations, and if the installation is temporary, quickdeploy, fly-away portable, or transportable — fixed to a truck, trailer, or mobile office — 1.2m VSATs are most useful, and for many sites, Ku band connectivity is sufficient,” says Jarrold. “If the site is operated on a longer timeframe say up to 12 months it may be more efficient to use cheaper fixed VSATs, also on Ku band.”

It was not long since Ku band and especially Ka band could not approach the reliability of C band.

That is clearly changing. Ka band coverage may not yet be optimal but, very importantly, the attenuation problem is being overcome. Simon Bull, senior consultant with specialised telecommunications consultancy company

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S19 ORA 1 2012 IT Feature_Layout 1 09/02/2012 11:22 Page 92

VSAT will generally work well in clear conditions but, unlike low-frequency satellite systems such as BGAN, it can be disrupted by heavy rain or dust storms.

Smaller, more portable MSS terminals also play an important role in connecting remote oil installations.

COMSYS**, says that over the US, Australia, Russia, Europe and most of Africa there is not a problem for Ka band with rain interference. However, where rain is infrequent but exceptionally heavy Ka is not ideal — in Nigeria for instance. “Typically we in the satellite industry talk about availability as being 99.8/99.9 per cent; that’s what’s acceptable to us,” he says. “It’s unlikely you're going to be able to hit those levels in, say, Nigeria with Ka band.” What does this mean for oil companies? “First of all it comes down to coverage. Besides the Global Xpress system, which raises a bunch of other questions, are you likely to have Ka band coverage?

And the answer is, in most instances, no. Is there

any prospect of getting Ka band? Not for the next five years probably, at least.”

Inmarsat’s Curran is, not surprisingly, more optimistic. “Ka band is starting to gain market acceptance, and we will be at the front of that wave with Global Xpress,” he says. “The Ka band satellites are very high powered, and the significant increase in spectrum available in that band offers a lot of potential. Yes there is some rain attenuation, but there have been major advances in terms of the air interface, with enhanced coding and modulation and, with better error detection and correction, that results in a much more resilient signal.”

VSAT case study 1: Meeting the demand for corporate connectivity IN RECENT YEARS multinational enterprises in Africa have been insisting on better connectivity. Take for example oil and gas. Field teams operations in Africa often find themselves working in difficult terrain and extreme weather conditions. In order to operate effectively they need to maintain a secured reliable network to ensure that all their information is synchronised and recorded without alteration or disruption.

IP telecommunications service provider SkyVision is meeting this increasing demand with an extensive range of solutions based on satellite connectivity designed especially for enterprises in emerging countries. They include: satellite internet connectivity, VPN (virtual private networks), private networks and VNO (virtual network operation) solutions.

SkyVision VPN is a professionally managed private corporate network. A fully customised, satellite-based virtual private network service completely managed

by SkyVision, the service was recently employed by a major bank in Nigeria to connect 90 new ATM sites to its headquarters.

SkyVision Private Network is a private network solution with a management option, making it ideal for enterprises and governments looking for security and control. Providing customised connectivity, the solution was recently acquired by a customer in Benin.

SkyVision VNO is backed by SkyVision’s VSAT facilities and enables service providers to operate their own VSAT network without the high cost of investment in teleport infrastructure. SkyVision’s VNO service is highly scalable and carefully engineered to meet the evolving needs of users with various network requirements. In addition, each VNO’s network bandwidth is physically separated from the resources of other users or service providers, and can be remotely configured and managed.

Doron Ben Sira, CEO of SkyVision, underlines an approach that includes deploying an increasing number of points of presence (PoPs), hubs and teleports throughout the continent. “A rising number of corporates in Africa can now communicate freely inside the African continent and with the world, while at the same time benefiting from a vital local presence that provides truly local support,” he says.

SkyVision has installed PoPs in Nigeria, Kenya, Zimbabwe and the Democratic Republic of Congo. In this way, it is able to offer single hop connectivity to local enterprises wishing to expand their businesses, without the need to rely on terrestrial infrastructure. The company also caters to a selection of fibre customers in Africa via its international submarine cables and POPs and offers a range of modular professional services, covering everything from planning to pre-deployment, deployment, operations and maintenance.

92 Oil Review Africa Issue One 2012

Whatever your choice of band, however, you’ll need to pay a fair amount to get an effective system for your oil rig. Is it worth it? That’s what we’ll discuss in our next issue. ■ Notes *The Global VSAT Forum (GVF) is an association of key companies involved in the business of delivering advanced digital fixed satellite systems and services to consumers, and commercial and government enterprises worldwide. GVF acknowledges the contribution of Northern Sky Research, the GVF Oil & Gas Communications Conference Series Content Partner, in the responses supplied for this article. The 16th conference in the series is planned for Luanda, Angola, in Q4 2012.

See www.gvf.org for more information.

**COMSYS is a specialised telecommunications consultancy company with a core expertise in satellite and VSAT systems. www.COMSYS.co.uk

VSAT case study 2: Know your customer

SUPPLYING VSAT NETWORKS means not just understanding the technology but understanding your customer’s needs. Shaun Young, regional director, Asia Pacific and Libya of Hermes Datacomms, a company that provides communications to the oil and gas industry, particularly in difficult and challenging locations, says: “VSAT is the preferred choice for delivering voice and data service when terrestrial connectivity is not available, not of sufficient quality and reliability or when mobility is required. Satellite delivers all the service that is available on terrestrial solutions including voice and video, corporate WAN and internet access.” However, he adds: “It is very rare for two customers to require the exact same service. VSAT technology provides plenty of scope and flexibility to engineer systems to deliver the service and application required to meet any customer demand, with the added benefit of reduced dependency on multiple terrestrial providers and their support networks. With satellite Hermes is very much in control of the data transport infrastructure, thereby limiting the risk of network outages.”

Hermes provides global communications specifically to the oil and gas industry, providing resilient and reliable links to centralised data centres on a managed network services basis. This is achieved by leveraging experience in the industry, meeting user needs rather than just selling bandwidth or a rigid technology.

“Hermes designs, delivers, maintains and supports all our satellite networks,” says Young. “By placing engineering and administration resources in the regions Hermes operate, we are better able to control and manage the satellite networks. And with teams spread out over the globe and a centralised training program Hermes is able to ensure continued service reliability.”

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X-RITE INC IS helping customers to streamline their workflows with the next generation of its popular NetProfiler software that can verify, optimise and certify handheld and benchtop spectrophotometers used at locations worldwide on a regular basis.

With the new NetProfiler 3.0, companies can calibrate spectrophotometers in design departments, on factory floors and in test labs to a single virtual standard, ensuring that colour measurements taken at distant locations are accurate and reliable throughout the supply chain.

NetProfiler 3.0 now extends the power of profiling to handheld devices with embedded profiling capabilities.

"We are particularly excited about our new NetProfiler solutions for handheld spectrophotometers, extending the benefits of profiling to new category of devices and customer workflows." said Richard Knapp, product manager for the software. He says all versions of NetProfiler 3.0 have improved speed and stability on personal computers and can be run offline to store profiles on portable USB memory sticks.

Another feature of NetProfiler 3.0 is its capability to profile new families of devices such as sphere-based instruments.

Schlumberger releases production operations software platform SCHLUMBERGER HAS RELEASED the Avocet 2012 production operations software platform. This has been engineered to combine a complete and up-to-date picture of operations with engineering analysis capabilities to pinpoint the reasons for production shortfalls, enabling producing assets to hit production targets consistently.

“Today, production engineers manage seven times more wells than they did in the mid-1990s,” said Meyer Bengio, vice president, petroleum engineering, Schlumberger Information Solutions. “The large number of wells combined with the significant increase in real-time data generated from permanent sensors has created a situation in which engineers only have time to react to well problems, rather than preventing them. With Avocet, engineers can be proactive with all of their wells and act with confidence to close the gap between actual and potential production.”

Avocet 2012 is a single, integrated platform that combines well operations and production data management systems - from capturing and validating field data, to production and equipment surveillance, and tracking of specialised oilfield operations. The Avocet platform supports production computations, visualisation of production networks, and reporting of current and historical information. Additional capabilities include component allocations, determination of artificial lift efficiency, AFE and workover performance tracking, and a tracking system to avoid costly well integrity problems and record well completion operations to meet regulatory requirements. Operators and engineers can assign classifications to better understand the reasons for production shortfalls.

For further information

LOG ONTO WWW.PORTWESTCOM

CALL OUR SALES OFFICE ON +44 (0)1709 894575 OR EMAIL INFO@PORTWEST.COM

Oil Review Africa Issue One 2012 93

Information Technology

X-Rite launches NetProfiler 3.0 software

Information Technology

S20 ORA 1 2012 IT News_Layout 1 09/02/2012 15:13 Page 94

Invensys/Shell agreement

VideoRay and Seebyte enter partnership

INVENSYS OPERATIONS MANAGEMENT has signed a multi-year, multi-million dollar contract to deliver comprehensive software solutions and services for Shell.

Under a new Corporate Enterprise License, Invensys will provide a suite of its SimSci-Esscor simulation solutions to improve Shell’s global upstream, downstream and petrochemicals production, helping it to achieve operational excellence. A critical part of the agreement will be Invensys’ ROMeo solution, an integrated software platform for simulation, data reconciliation, optimisation and operations decision support. Invensys will also supply its PRO/II, Pipephase and Dynsim software, along with several other software solutions, training and support services. The Corporate Enterprise agreement allows Shell access to Invensys software packages on a global basis within Shell’s IT infrastructure, enabling enhanced use of simulation software across all Shell business units.

“Shell needed cost-effective, flexible access to our open simulation and optimisation software across its global organisation without any restrictions,” said Tobias Scheele, vice president, advanced applications, Invensys Operations Management. “We have been working with Shell and providing them service and solutions for more than 30 years. This license strengthens our long-standing relationship with Shell, who will use our SimSci-Esscor ROMeo optimisation software and our other family of simulation and modeling solutions to deliver increased value around the globe, helping them to achieve operational excellence in real time.”

Invensys Operations Management’s ROMeo software provides a leading unified modeling environment for off-line and on-line optimisation. In use at dozens of upstream facilities, refineries, petrochemical and chemical plants worldwide, the software supplies a scalable environment for optimising all major units, as well as other aspects of plant profitability, such as utilities and instrument/equipment performance.

SEEBYTE AND VIDEORAY have entered a partnership with the aim of developing solutions to improve value to their customers.

The decision follows the success of SeeByte’s SeeTrack CoPilot integration with the VideoRay micro ROV which was demonstrated at VideoRay’s VIPS 2011 conference last month in Florida. The demonstration, which featured Teledyne RDI Phased-Array DVL (Doppler Velocity Log) navigation, real-time monitoring and DP (Dynamic Positioning) control, supported both companies’ strategies to bring new piloting solutions to the Inspection Class ROV market.

Having witnessed the success of the SeeTrack CoPilot and VideoRay integration, CEOs Bob Black and Scott Bentley formalised the companies’ agreement to develop a partnership that will continue to address industry requirements and add value to the VideoRay product line.

Bentley, VideoRay CEO, commented: “This partnership will see two great brands working together to deliver customer-focused technology that will essentially enhance the user experience.

SeeByte has shown that their software complements the practical use of our micro ROVs and I look forward to building upon this relationship and announcing our new offering in early 2012.”

Bob Black of SeeByte also commented on the agreement: “VideoRay are the market leaders for micro ROVs and SeeByte is delighted to be working with such a company to automate the piloting of their vehicles. I believe that we can add great value to the VideoRay product, and I think it is fair to say that this partnership is a fantastic example of how strategic commitment can pay dividends.”

Subscription Form 2012

Advertiser’s Index company..................................page African Reinsurance Corp. ..................8 Aggreko Middle East Limited ........60 Alduco Energy........................................65 AMDS Courier Services......................17 Arik Air Limited......................................25 BG Technical Limited ..........................33 Broron Oil and Gas Limited..............57 BVEE International ..............................37 CapRock....................................................13 Century Energy Services Limited..95 Container World Pty Limited ..........71 CWC Associates Ltd (Ghana Summit 2012)........................27 Cygnus Instruments Ltd....................59 Damagix Nigeria Limited..................20 Dateline Energy Services Limited....................................43 Emerson Process Management ......7 Emirates ....................................................31 Eunisell Limited ....................................39 Exhibition Management Services (Oil & Gas Africa 2012)........................69 Expro International Group PLC......35 Exterran ....................................................23 ExxonMobil Corp. ................................15 Fortune Global Shipping and Logistics Limited..........................61 Fugro Geoteam AS ..............................11 GCA Energy Limited............................81 Global Oceon Nigeria ........................67 Ibafon Oil Ltd..........................................47 International Exhibition Services S.r.l. (SAOGE 2012) ............79 Isisan ..........................................................77

Kohler Power Systems........................34 Kwikspace Modular Buildings (Pty) Ltd................................32 Marelli Motori S.p.A. ............................96 Marlin Maritime Ltd ............................49 Nadabo Energy Group ......................53 Nelson Dreil Limited............................52 NHV Aviation ..........................................87 Oando PLC..................................................5 Oil Country Tubular Ltd (OCTL)......55 Oilways Logistics & Energy Ltd ......46 PEM OFFSHORE ....................................63 Portwest....................................................93 Prakash Steelage Ltd...........................41 Saudi Leather Industries Company Ltd. ..............................................................36 Sevmorneftegeofizika / SMNG......75 SGS Inspection Services Nigeria Ltd ............................51 Shree Steel Overseas FZCO..............84 Sky Vision Global Networks ............91 Society of Petroleum Engineers....86 South Atlantic Petroleum....................2 Subsea 7 ......................................................9 Suraj Limited ..........................................83 Tilone Subsea Ltd. ................................45 Tolmann Allied Services....................21 Topher Zhang Vocational Centre ................................28 Toprope ....................................................19 United Metallurgical Company / JSC OMK ..........................85 Vandrezzer Energy Services ............72 Welltec A/S ................................................9 WorleyParsons ......................................29

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