Oil Review Africa 6 2012 by Alain Charles Publishing

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■ Gas - p26 ■ Geology - p28 ■ Exploration - p32 ■ Technology - p42

Volume 7 Issue Six 2012

Africa

Covering Oil, Gas and Hydrocarbon Processing

Quieter markets ahead? LNG: prices, prospects and positioning

www.oilreviewafrica.com

East Africa’s gas boom

Experts cautiously optimistic about East African O&G Building relationships in Uganda Ghana’s gas project The growth in digital gas lift Utilising lubricants to reduce downtime Reducing exploration timelines and supporting seismic with FTG

Hon Kiraitu Murungi, EGH, MP Minister for Energy in Kenya. See page 20

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

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“Keep your love of nature, for that is the true way to understand art better.” VINCENT VAN GOGH

E N J O Y C H A M P A G N E L A U R E N T- P E R R I E R R E S P O N S I B LY . l a u r e n t - p e r r i e r . c o m

S01 ORA 6 2012 Start_Layout 1 12/12/2012 15:32 Page 3

■ Gas - p26 ■ Geology - p28 ■ Exploration - p32 ■ Technology - p42

Contents

Volume 7 Issue Six 2012

Africa

Covering Oil, Gas and Hydrocarbon Processing

Quieter markets ahead? LNG: prices, prospects and positioning

www.oilreviewafrica.com

East Africa’s gas boom

Experts cautiously optimistic about East African O&G

Columns Industry news and executives’ calendar

Building relationships in Uganda

Ghana’s gas project The growth in digital gas lift Utilising lubricants to reduce downtime

Analysis Quieter markets ahead?

Reducing exploration timelines and supporting seismic with FTG

Circumstances sugges that today’s price for the OPEC ‘basket’ won’t last in the medium term. One of these is the rapidly improving production capacity of Iraq.

LNG: prices, prospects and positioning

Hon Kiraitu Murungi, EGH, MP Minister for Energy in Kenya. See page 20

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

Southey Offshore expands in East Africa.

East Africa East Africa’s gas boom: taking starting positions

Transparency is key to Kenya’s energy future

Oil Review talked to the Hon Kiraitu Murungi, EGH, MP Minister for Energy

Tullow Oil building relationships in Uganda

Experts cautiously optimistic about East African oil and gas

Interview Atlantic Energy making new strides

An interview with Scott Aitken, Co-Chief Executive Officer of Atlantic Energy.

Gas Ghana’s gas project

Efforts by the Ghana government to begin the delivery of gas this month have been hampered by delays .

Geology News and developments

A round-up of new geological activity from around the region.

Exploration News and developments

Editor’s note WITH EAST AFRICA having been ignored for a very long time by oil and gas majors, companies are now scrambling for a piece of the action as the vast reserves of gas there become key to plans to use LNG (liquefied natural gas) as a way of ensuring increased demand for fossil fuels is met during the next few decades. Significant gas reserves have been found in Mozambique and Tanzania, where LNG facilities are now being planned, and the Pacific LNG Basin will be the main target. East Africa’s distance to large markets like India and East Asia is not dissimilar from Qatar’s. Kenya's first oil discovery has seen a surge of interest in new oil exploration licenses, and has boosted the country's oil reserves estimate by one third to around four billion barrels, the largest in East Africa. Successful oil discoveries in Kenya should bode well for landlocked Ethiopia, given their geological similarities. East Africa may be the new hotspot for explorers but the region will first need to invest in infrastructure to develop and transport the products for domestic and international consumption. On-the-job education and training will also be paramount, as well as transparency and effective public institutions that are responsive to citizens. What matters most is the effective management of the resources.

Gabon plans offshore licensing round for 2013.

Technology The growth in digital gas lift

The growing potential of digital gas lift in African operations, particularly offshore.

Utilising lubricants to reduce downtime

Taking advantage of various advanced lubricants in order to maintain equipment.

Information Technology Reducing exploration timelines and supporting seismic with FTG

The acquisition of broadband, high resolution gravity data throughout the exploration cycle is having a significant impact on workflows. Operators in East Africa should take note.

Satellite communications

Satellite communications service are changing - slowly. Could competition cut communications costs?

50 Reducing exploration timelines and supporting seismic with Full Tensor Gravity Gradiometry.

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Africa

Covering Oil, Gas and Hydrocarbon Processing

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Oil Review Africa Issue Six 2012 3

Industry News & Events

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Executives’ Calendar 2013 JANUARY 21-23

East Africa New Frontier Exploration Forum

LONDON

21-24 28-29

Oil & Gas Infrastructure Security Middle East & North Africa Energy 2013

ACCRA LONDON

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6th Gas Tech Cairo 2013 7th Sub Saharan Africa Topsides, Platforms & Hulls Conference EAPCE' 13 FLNG Nigeria Oil & Gas

CAIRO CAPE TOWN GALVESTON ARUSHA LONDON ABUJA

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Subsea Tieback Forum & Exhibition EAPCE '13 Angola Recruitment Summit Mozambique Gas Summit Oil & Gas North Africa Offshore West Africa ARA Week 2013 Oil and Gas Telecommunications 5th African Petroleum Conference and Exhibition

SAN ANTONIO ARUSHA LISBON MAPUTO ROME ACCRA MARRAKECH LONDON LIBREVILLE

www.subseatiebackforum.com www.eac.int/eapce www.eliteic.net www.mozambique-gas-summit.com www.thecwcgroup.com www.offshorewestafrica.com www.ifrra.org www.smi-london.co.uk www.cape-africa.com

Ocean Business SPE NATC 2013 LNG 17 9th Western Africa Oil, Gas & Energy Week Ghana Summit

SOUTHAMPTON CAIRO HOUSTON WINDHOEK ACCRA

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FEBRUARY 4-5 4 5-7 6-8 13-14 18-21

MARCH 5-7 6-8 8-10 11-13 18-20 19-21 19-23 20-21 26-28

APRIL 9-11 15-17 16-19 22-24 23-26

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

Financial leaders to speak at Nigerian oil and gas event THE NIGERIAN FEDERAL Ministry of Finance, Diamond Bank, Stanbic Bank and Access Bank will be among a host of top financial institutions set to supply speakers to the Nigeria Oil & Gas Conference & Exhibition 2013's Energy Finance Seminar Nigeria's finance ministry confirmed its endorsement of the CWC-organised event, which will take place from 18-21 February 2013 in the Nigerian capital of Abuja. Danladi Irmiya Kifasi, permanent secretary of the Federal Ministry of Finance, and Budget Office of the Federation director-general Bright Okogu will present the event's finance seminar on 18 February 2013. Senior representatives from key Nigerian banks, including Diamond Bank, Stanbic Bank and Access Bank, will discuss the country's current financial structure, domestic and international investment opportunities, and explore the future of financing projects in the Nigerian energy sector. The 2012 Nigeria Oil & Gas Conference & Exhibition attracted more than 1,000 conference delegates, 180 exhibitors and 7,500 visitors. Next year, the 13th edition of the event will place a special focus on the impact the Petroleum Industry Bill could have on the industry if passed, as well as holding a number of networking functions including the Annual Nigeria Oil & Gas Awards Gala Dinner.

4 Oil Review Africa Issue Six 2012

Ghana to host 2013 summit in Accra THE 4TH GHANA Summit, endorsed by the Ministry of Energy Ghana, Ghana National Petroleum Corporation (GNPC), Ghana Gas, Volta River Authority and President John Dramani Mahama, will bring together key industry experts, providing networking opportunities within the oil and gas industry. The oil and gas exhibition, which is being organised by CWC, will be held at the Accra International Conference Centre on 23-25 April 2013. Backing the event, John Dramani Mahama, President of the Republic of Ghana, explained, “As an emerging oil and gas economy, Ghana is bound to face challenges consistent with that industry. “The Government is aware that the best way to confront these challenges in order to achieve its ‘Better Ghana Agenda’ is by shared experiences. “That is why the platform which you provide stakeholders and other industry players in the oil and gas industry to share ideas, experiences and information is commendable.” Among the speakers will be Ghana’s deputy minister of energy, Alhaji Inusah Fuseini, CEO of Petroleum Commission, Dr Kwabena Donkor, CEO of GRIDCo, Charles A Darku and managing director of Electricity Company of Ghana, William Hutton-Mensah. Topics that will be discussed at the summit include Ghana’s current growth strategies which are working towards optimising the country’s resource potential and the way upstream challenges and opportunities in Ghana should be met. This year’s event was host to more than 2,000 visitors, which included more than 400 delegates providing them with opportunities to introduce new products to local and international investors. According to CWC, 94 per cent of exhibitors who attended the event found it useful for establishing future contacts. The event next year aims to give key stakeholders in the region opportunities to meet decision makers from within the value chain and give companies the opportunity to establish their brand in the Ghana oil, gas and power sector marketplace.

S02 ORA 6 2012 News_Layout 1 12/12/2012 15:33 Page 5

EAOGS a resounding success

THE NIGERIAN NATIONAL Petroleum Corporation has pledged to partner with the Nigerian Content Development and Monitoring Board to grow Nigerian Content in the oil and gas industry to the 70 per cent target set by the Federal Government, especially in the complex deep offshore. The Group Managing Director of NNPC, Andy Yakubu, who spoke at Practical Nigerian Content Conference held recently, reported that the participation of Nigerian Content in the industry, especially in the upstream, has substantially increased from a merger 10 per cent before the enactment of the law to more than 30 per cent, citing the example of the recent USAN Deep Offshore Field development. “These percentages are even higher and in some cases have attained 100 per cent, for example the Utorogu Gas Plant Expansion Project,” he added. The GMD listed other projects with high Nigerian Content value to include the OB3 Pipeline Project, Escravos Lagos Pipeline Phase 2, the Aba Depot and Okirika Jetty Rehabilitation Project. He explained that windows of opportunities to grow Nigerian Content exist in the upstream, midstream and downstream segments of the oil and gas value chain to grow Nigerian Content. Yakubu also advised Nigerians to set up medium sized companies in both exploration and production in areas like well services engineering, measurement, mud and logging engineering services.

THE EAST AFRICA Oil and Gas Summit (EAOGS) 2012 co-hosted by the Ministry of Energy, Kenya and Global Event Partners (K) Ltd was a resounding success welcoming 326 delegates to the Summit which took place in Nairobi midNovember. Hon. Kiraitu Murungi, Minister of Energy, Kenya gave the opening speech to welcome participants to the Summit, ‘‘The East Africa Oil & Gas Summit has brought together a very rich galaxy of petroleum industry players, professionals and senior officials from the corporate world and business community from all over the world. I want to most sincerely thank the organisers of this summit, Global Event Partners for putting together this prestigious conference,’’ said the Minister. Over 170 international and regional companies attended EAOGS including ministries, NOCs, IOCs, service companies, leading consulting and contracting companies, financial and legal institutions, government authorities , embassies and industry associations. This prestigious delegation of senior level industry professionals and government officials attended from 29 countries; Australia, Belgium, Canada, China, Egypt, France, Germany, Italy, Israel, Japan, Kenya, Korea, Kuwait, Malaysia, Mozambique, Netherlands, Nigeria, Norway, Pakistan, Somalia, South Africa, South Sudan, Sweden, Switzerland, Tanzania, Trinidad, Uganda, the UAE, UK and USA. The Managing Director, National Oil Company, Kenya, Sumayya HassanAtthmani was impressed with the international delegation present saying, ‘’The first East Africa Oil & Gas Summit has been a great success. It has presented tremendous networking opportunities with many different players across the industry and from many different countries.’’ Sumayya Atthmani chaired the session on opportunities in Kenya and spoke in the session on infrastructure opportunities in East Africa. She explained the need for collaboration between countries across the region in infrastructure development and financing in order to bring newly discovered oil and gas resources to resources to market.

GEFCO, INC. an Astec Industries Company 2215 SOUTH VAN BUREN · ENID, OKLAHOMA, USA 73703 · PHONE 580.234.4141 Â GRPVDOHV#JHIFR FRP Â LQWVDOHV#JHIFR FRP · www.gefco.com

Oil Review Africa Issue Six 2012 5

Industry News & Events

NNPC to grow Nigerian Content to 70 per cent

Industry News & Events

S02 ORA 6 2012 News_Layout 1 12/12/2012 15:33 Page 6

Major changes coming says IEA THE GLOBAL ENERGY map is changing dramatically says the International Energy Agency in its latest World Energy Outlook (November 2012). “These changes will recast expectations about the role of different countries, regions and fuels in the global energy system over the coming decades.” Africa will be far from immune from any of this, most notably as supply pressures ease with the continuing rise of North American output of both oil and gas, and as the market for LNG evolves with the falloff in US import demand. In fact under the Agency’s central (‘new policies’) scenario the USA is expected to become a net exporter of gas by 2020, and the North American region as a whole will become a net oil supplier soon after as the US becomes almost self-sufficient in energy overall.

Subsea 7 wins contract for offshore Africa OILFIELD SERVICES FIRM Subsea 7 has been awarded a US$150mn EPCI (engineering, procurement, construction and installation) contract by Chevron for the development of the Lianzi field, located offshore Angola and the Republic of Congo. The work includes the delivery of a 200-ton module hosting a highvoltage generation system for a new subsea 'direct electrically heated' pipeline cable, an 80-ton flow meter deck extension and various upgrades on the platform. The project will make use of local personnel and resources in Angola and the Republic of Congo. Onshore fabrication will take place in both countries and will be conducted by Subsea 7's Angolan joint venture, with the offshore works scheduled for delivery in the second half of 2014. "Following the award to Subsea 7 earlier this year of the subsea installation works for the Lianzi development, we are proud of the award of the topsides modifications works, which demonstrates our proven capabilities in the offshore hook-up and revamping segment," Olivier Carre, Subsea 7's senior vice president for Africa and the Gulf of Mexico, commented in a company statement.

6 Oil Review Africa Issue Six 2012

Cameron and Schlumberger join up CAMERON AND SCHLUMBERGER have created a joint venture to manufacture and develop products, systems, and services for subsea oil and gas applications. The venture is named OneSubsea and will consist of Cameron’s existing subsea division and Schlumberger’s Framo, Surveillance, Flow Assurance, and Power/Controls businesses. Cameron will receive US$600mn from Schlumberger and will manage the new venture. “Our new venture with Schlumberger provides a powerful marriage of their oilfield services technology and our subsea equipment heritage,” said Jack B. Moore, Cameron chairman, president, and CEO. “It leverages Cameron’s flow control expertise, world class manufacturing and aftermarket capabilities.” “This new joint venture … is uniquely positioned to optimise complete subsea production systems and help our customers improve production and recovery from their subsea developments,” said Paal Kibsgaard, CEO of Schlumberger. “The broad scientific and technology platform that Schlumberger brings will enable a total system approach, leading to a unique and differentiated offering in this rapidly growing market.”

Smit Lamnalco newbuilds for Gabon SMIT LAMNALCO HAS renewed its marine support services contract with oil major Shell in Gabon, in a deal that has triggered investment in three auxiliary vessel newbuildings. The five year contract renewal extends an uninterrupted relationship between the marine support specialist and Shell Gabon dating back to the 1990s. It covers support for Shell Gabon’s tanker operations at the remote Gamba Terminal, south of Port Gentil. “The trust Shell Gabon has in our services has sustained through the 2011 merger of Lamnalco and SMIT Terminals.” says Aart van der Wal, Managing Director Smit Lamnalco Africa. The renewal covers the deployment, crewing and management of four Smit Lamnalco support vessels, with three newbuilds ordered in midNovember to replace existing tonnage. The orders

cover one ‘Shoalbuster’ and one Beach Landing Craft from Damen Shipyards, plus one Fast Offshore Crew Boat the UK-based and well-known supplier to West Africa Alnmaritec. An existing ‘Shoalrunner’ auxiliary vessel will remain in place. “Our willingness to invest in new tonnage was clearly a factor in the renewal” says Mr Van der Wal. “It is in line with our strategy to offer one of the youngest and most efficient marine and offshore support fleets in the industry.” The Shoalbuster is a versatile, multi-purpose vessel for harbour, inland and coastal waters, characterised by high bollard pull and ample deck space. Meanwhile, the manouevrability of the 17m long, 25-knot plus, aluminium-hulled fast response vessel will be conferred by its double chine hull and Rolls-Royce Kamewa FF45 water jets.

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Industry News & Events

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Technip scoops second Angola gig TECHNIP HAS BEEN awarded an engineering, procurement, construction and commissioning (EPIC) contract by a subsidiary of fellow French company Total for the second phase of the Girassol Resources Initiatives development project. The field is located 210 km offshore Angola, at a water depth of 1,300 m. Total E&P Angola handed down the deal, which covers the project management, engineering, fabrication and installation of 21 km of umbilicals and 13 km of interconnecting power cabling between the Dalia and Girassol FPSO units, both delivered by Technip. The contract also includes the recovery and disposal of four rigid spools and the installation of eight new flexible spools. The project management and engineering work will be undertaken by both Technip Angola Engenharia and Technip UK. Some fabrication work will be completed by the Angelex spool base in Dande, Angola, and some will be completed in Le Trait, France. The company had completed the first phase of the project earlier this year. The offshore campaign is scheduled for the end of 2014, with the main installation vessel being from Technip’s fleet

Stork awarded global frame agreement STORK TECHNICAL SERVICES, the leading global provider of knowledgebased asset integrity management services for the oil and gas, chemical and power sectors, has secured a global frame agreement with Subsea 7 to deliver a range of inspection and expediting services. The agreement, over the next three years, will see Stork’s Quality Services division provide qualified discipline engineers, auditors and inspection personnel to represent Subsea 7 at its approved suppliers. This will ensure that the manufacture of equipment, such as Subsea Structures, manifolds, umbilicals and pipe lines, is supplied in accordance with the required specifications, inspection and test plans. Stork will deliver its services on a global basis in line with Subsea 7’s key operating regions. Dave Workman, COO for Stork Technical Services, said: “We are very pleased to have secured this global frame agreement and it is the most significant to date for our Quality Services division. The consistent, safe and high quality work that our team delivers was a significant factor in the award and has to be commended. I am confident they will replicate this standard throughout the agreement and we look forward to partnering with Subsea 7 over the coming years.” Nils Anderstrom, Subsea 7 Group Commodities Director, said: “We see this as a strategic agreement aimed at ensuring persistent high quality, effectiveness and efficiency in our post-award activities with our suppliers. This shall provide our projects globally with predictable and dependable deliveries further securing our well established ability to satisfy or surpass our client requirements and expectations”

Ugandan Parliament passes long-awaited oil bill THE UGANDAN PARLIAMENT has passed the long-awaited upstream oil bill after nearly a year of back-and-forth parliamentary deliberations as the East African nation prepares to transit from oil exploration to the production phase. Ruling National Resistance Movement party law makers voted to pass the bill after forcing through an amendment reinstating a clause that gives the oil minister powers to solely approve and revoke licenses. Stephen Birahwa, a law maker on the natural resources committee, said ruling party

lawmakers had earlier reached a "compromise" with the president to reinstate ministerial powers in order "to strengthen state control in the sector". "Oil is a very important resource and it needs to be presided by a minister with real powers," Mr. Birahwa said. The bill, which will regulate oil licensing, exploration and development, was introduced in the house in February, but its approval has dragged on for several months, amid a bitter spat between parliament and the executive over key amendments,

including the powers of the oil minister. In October, lawmakers introduced an amendment, trimming the minister's powers of approving, granting and revoking oil licenses. Government initially consented to the amendments but later backtracked, creating a bitter standoff. George Boden, a campaigner with UK-based Global Witness said by reinstating the clause about ministerial powers, the minister will be allowed to negotiate deals behind closed doors with no public scrutiny, which will promote corruption.

Leighton completes Tanzania project AUSTRALIAN CONTRACTOR LEIGHTON Offshore has completed a single point mooring (SPM) project southeast of the Port of Dar Es Salaam. Leighton carried out the design, engineering, procurement, fabrication, installation and precommissioning of a replacement SPM and pipeline system. The SPM system was installed for the import of crude and white products and is able to accommodate large tankers with up to 150,000 dead-weight tonnage. “We are proud to have worked with the Tanzanian Ports Authority to complete this project which included a number of technical

8 Oil Review Africa Issue Six 2012

firsts, including a complete pigging of the system through the SPM and pipelines, and some challenging work in trenching through the intertidal zone,” Leighton Offshore chief executive, Boyd Merrett, said. “This is an important facility for Tanzania and neighbouring countries, and we are very pleased to have been part of this project development. We are continuing to focus on East Africa as a market, where there are significant potential offshore oil and gas projects in early stages of development.” Leighton added the first tanker of imported white product (diesel) had already been offloaded.

S03 ORA 6 2012 Analysis 01_Layout 1 12/12/2012 15:35 Page 9

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Analysis

Circumstances suggest that today’s price for the OPEC ‘basket’ won’t last in the medium term. One of these is the rapidly improving production capacity of Iraq.

Quieter markets

ahead? Iraq will make “by far the largest contribution to global oil supply growth over the coming decades”.

FTER THE TEMPORARY Libyan withdrawal, all-Africa’s oil output continues its slow and unsteady rise. But two recent reports (both dated October 2012) from the International Energy Agency suggest that a period of price weakness lies ahead because of potential global over-supply. So the question is, will the recent healthy pace of E&D in Africa continue in such uncertain circumstances? The main issue on the supply side is the continuing rise in US production, which was up 3.6 per cent last year (BP figures) and now accounts for close on one-tenth of global production. This seems to be starting to mirror, somewhat faintly, the recent turnaround in North American gas output, with EOR primarily the cause. On the demand side the prevailing issue continues to be slow economic growth, especially in the OECD countries (notably Europe) but now starting to affect China too. However the “elephant in the room” is the rapidly improving production situation in Iraq, which saw a 12.8 per cent increase in output last year. If this continues, the signs are that this OPEC country could soon start to supplant some of Africa’s growing sales in Asia. Even if not it will almost certainly contribute to general price weakness.

Global map to be redrawn On 12 October the IEA claimed that the global map of oil trade will be redrawn over the medium term. “Profound shifts in the regional distribution of oil demand and supply growth will redefine the refining industry and transform global oil trade over the next five years,” says their annual Medium-Term Oil Market Report. “The oil market is at a crossroads. On each and every front … potentially game changing

12 Oil Review Africa Issue Six 2012

developments are taking place,” said Executive Director Maria van der Hoeven. High on the list of these is undoubtedly the situation in Iraq. “Among OPEC producers, Iraq stands out as its production capacity is expected to enter a new growth phase, which may continue even beyond the forecast period [2015]”. Just three days before the Paris-based agency, an energy monitoring service funded by the industrialised countries, had issued a landmark report on the Iraq Energy Outlook. This is effectively a peek into some of the findings of their huge and highly influential World Energy Outlook, a long-term survey, which is scheduled for publication mid-November. The finding of this is that Iraq will make “by far the largest contribution to global oil supply growth over the coming decades”. With current production of three million barrels per day (mn bpd, it was less than 2.5 as recently as 2010) this could more than double by 2020, and reach 8.3mn bpd (or even as high as 10.5) by 2035. So Iraq will likely become a key supplier to fast-growing Asian markets, such as China, and the world’s second largest oil exporter by the 2030s. Hence our reference to elephants and architecture.

Profound impact on Africa The IEA doesn’t actually say this, but undoubtedly the impact here in Africa will be profound. Last year combined sales from West Africa to China and India reached 71.7 mn tonnes, nearly onethird of the sub-regional total. This was more than WA sold to the USA, its traditional principal market. (We have excluded the North from this 2011 analysis because of the exceptional circumstances that prevailed in Libya). However taking action on account of this forecast is difficult because of the number of uncertainties about Iraq’s future supply potential – and willingness to produce more – that exist.

First there are the many impediments to the investment that would be needed to achieve increases of this order, even in such relatively simple matters as water (for injection to maintain output) and mains power supply. Then, as the IEA points out, there’s the question of precisely how Iraq plans to derive sustainable long-term value from its huge oil (and later gas, of course) reserves – which must reflect “success in consolidating political stability and developing its human resource base.”

Profound shifts in the regional distribution of oil demand and supply growth will redefine the refining industry and transform global oil trade over the next five years. Another factor they identify is the “capacity of international markets to absorb the growth in production…There are arguments for allowing production capacity to run ahead of actual output”. On the more positive side they point out that if their “High” case (a number of scenarios is a feature of IEA outlook reports) is realised this “would match the highest sustained growth in the history of the industry.” This is a reference to the boom in Saudi Arabia between 1966 and 1974; very different circumstances prevail in the Iraq of today. For further details of how this fascinating story with all its major implications for both North and West Africa is likely to evolve look out for the report on this year’s WEO in the next issue of Oil Review Africa. ■

S03 ORA 6 2012 Analysis 01_Layout 1 12/12/2012 15:35 Page 13

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Analysis

S03 ORA 6 2012 Analysis 01_Layout 1 12/12/2012 15:36 Page 14

Which territories are the ones to watch for LNG producers and buyers? How will LNG be affected by price? And is it really a viable alternative to pipelines? The author of a new report on global LNG trends discusses these and other questions with Phil Desmond.

LNG: prices, prospects

and positioning T

HE LATEST EDITION of The World LNG Market Report* from DouglasWestwood highlights LNG facilities’ capital expenditure over the 20122016 period. It examines new prospects for LNG liquefaction and regasification terminals and LNG carriers, looks at the technology underlying the LNG business and presents market forecasts for activity in the sector. However, many players in Africa will ask: what does this mean for the industry across this continent? For example, at a time when gas supply is a growing requirement of a number of countries across the world, what is the potential of Angola? And are Mozambique and now Tanzania also likely to be major players in LNG?

One interesting possible future trend is floating LNG. Mozambique and Tanzania are able to work mainly from gas fields. The Angolan projects tend to work with associated gas. That’s not the only difference. “Angola has scope for expansion but I think this may be a while off,” said lead analyst and author of the DouglasWestwood report, Lucy Miller. Prospects are brighter for Tanzania and Mozambique, it seems. She added, “BG Group [a major player in natural gas exploration and delivery] is planning an LNG plant off Tanzania while Anadarko is developing an LNG project for its finds off Mozambique. However,” she added, “given the lead times for LNG projects it is unlikely that any of these terminals will be completed within the next five years as both are in the engineering stages and exploration is ongoing. Start-ups towards the end of this decade or early next decade are a more likely estimate.”

In any case there won’t be a need for liquefaction facilities for the entire output. Some countries will work with pipelines. So an obvious question is: why LNG? Are pipelines sometimes going to be a better idea? In other words, what are the economic up and downsides of LNG? Some are practical and some political, as Miller explained. “LNG competes with pipelines over long distances, especially any pipelines which are subsea. LNG also has political advantages since sensitive regions or countries can be avoided.” However, another advantage of LNG is its flexibility. “Most of LNG is traded under long-term contracts but sometimes a buyer can purchase cargoes and send them to other countries — really anywhere with an appropriate regasification terminal. Since there is no universal gas price this means you can send LNG from a country with a low price to those with high prices.” The price of LNG may nevertheless soon be a problem, however. It seems that not just Australia and the US but many other regions are uncovering significant gas prospects. With such widespread availability are buyers going to accept the sort of term contracts that made Qatar rich? At the time of writing local gas price were low and, it seems, still are, “but we don’t believe this is sustainable long term,” said Miller. Prices in Asian countries, especially Japan and Korea, have been pretty high, and that would undoubtedly benefit Qatar and Australia over the US, given the shorter transport distances. A similar calculation may

benefit certain African suppliers, although it’s hard to second-guess the movement of the market at this early stage. One interesting possible future trend is floating LNG. The vast output due from offshore Australian fields could boost FLNG investment. But is FLNG still too costly an option for many other markets? Not necessarily, Miller said. “FLNG developers believe that it can have cost advantages in certain conditions. They are positioned on field, so reduce the amount of onfield infrastructure required and [the need for] any long subsea pipelines to shore. Also they can be constructed in a shipyard — a more controlled circumstance for cost considerations.” Those are the upsides. “However,” she added, “most FLNG units are pretty small — 2-3mmpta — and don’t offer the same scope for expansion as onshore — although you could always add another vessel — so large-scale LNG projects are likely to remain onshore.” Still, FLNG is being looked at for fields worldwide — and not just Australia although these plans are some of the most advanced. “There are also some interesting projects off Southeast Asia, Latin America, West Africa and North America,” said Miller. *World LNG Market Forecast 2012-2016: is the latest in a series of business studies by Douglas-Westwood an independent company and leading provider of business research & analysis, strategy and commercial due diligence on the global energy services sectors. For prices and further information, see www.douglaswestwood.com/shop ■

Promising resource estimates Nevertheless the resource estimates for both countries are promising. But Africa — east and west — shouldn’t celebrate too soon. “There are some concerns,” said Miller, “as major LNG projects in other sub-Saharan countries such as Nigeria and Angola have seen considerable delays and both Tanzania and Mozambique are relatively underdeveloped compared to other parts of Africa [so] some slippage in timing may occur.”

14 Oil Review Africa Issue Six 2012

Plans have already been hatched in East Africa to export 36mn tonnes of LNG a year. But the plays remain at the early stages, with hurdles to overcome.

S04 ORA 6 2012 Analysis 02_Layout 1 12/12/2012 15:36 Page 15

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East Africa

The oil and gas discoveries made in the past few years, first in Mozambique and then in Tanzania, have switched the global gas spotlight onto the East African offshore play and its potential. Samuel Cuciszuk reports.

East Africa’s gas boom:

Taking starting positions A

S 2012 DRAWS to a close, the extent and viability of the coming East African gas boom, centring on Mozambique and Tanzania – but possibly extending to Kenya - is becoming clear. Large offshore deepwater discoveries have not only raised the promise of transforming the economies of the two countries, but are having a potential game-changing impact on the future LNG market in the Pacific Basin and raise question marks over the viability of some of Australia’s later LNG developments. However, as oil and gas companies and market actors position themselves for a coming gas boom, major hurdles remain, as dreams of rapid megaproject development comes up against the realities of skill shortages and some of the world’s least developed infrastructures. In the meantime, oil discoveries and their development in Uganda have come to seem like yesterday’s news, given the long holdup caused by taxation disputes in the past two years. Recent discoveries in north western Kenya have however turned the spotlight back onto the wider area, particularly since it looks like development will start to genuinely get underway in the coming year.

World class region in the making The oil and gas discoveries made in the past few years, first in Mozambique and then in Tanzania, have switched the global gas spotlight onto the East African offshore play and its potential. Anadarko alone, which early on secured a prime spot in the area, has firmed up gas reserves of between 17-30 tcf, with continued exploration possibly lifting that number considerably. Eni, another early arrival, believes the gas in place in its Area 4 license offshore Mozambique could be as high as 40 tcf and a handful of other actors, like BG and Statoil, are hopeful as their programmes in the Rovuma basin follow up promising leads collected during the first phases. Off southern Tanzania, just on the other side of the maritime boundary, large scale discoveries totalling around 15-20 tcf have been made too, although the Rovuma basin’s northern extension into Tanzanian waters is much more limited, which likely will cap its potential compared to Mozambique. Still, while early days, it remains clear that both countries are looking at a future as gas exporters, with LNG looking like the selfevident option given the very limited gas market in inland Africa. The first concrete plans for an LNG facility are

16 Oil Review Africa Issue Six 2012

East Africa has become a hot spot for oil and gas exploration after new discoveries, most recently in Kenya.

being drawn up by Anadarko, which is mulling a scalable facility starting with two five mmtpa liquefaction trains, with the potential to subsequently increase it to six same-sized units. The company is deciding in favour of an onshore facility, despite floating liquefaction(FLNG) being suggested by many since the first discoveries were made. Given the reserve volumes now underpinning the LNG venture, the sheer size of even the first phase speaks in favour of piping the discoveries to the mainland. FLNG remains an expensive and still fairly untested technology, with its main strength being its ability to allow monetisation of stranded offshore discoveries. It is however not particularly scalable, unless one places several FLNG vessels at the gas field in question – a solution which quickly becomes inferior in economies of scale to building a subsea pipeline to the coast and building a cheaper onshore facility for the liquefaction – at least given the distances involved in this case.

Competing in Asia-Pacific This is not only a marginal calculation. Costs and project cost control - will be imperative at the East African developments, which will be coming onstream at a very competitive time.

Costs - and project cost control - will be imperative at the East African developments. Mozambique’s gas exports, followed at a (probably) slightly later stage by Tanzania, will come onstream at the same time as several Australian and Papua New Guinean LNG ventures, likely leading to a squeezed marketing situation which at least for a while might create a buyers’ market in the Pacific Basin. Crucially, as plans are starting to take concrete shape in East Africa and reserves are being proven, a certain level of apprehension - even fear - is starting to spread among gas producers and financiers of the Australian LNG boom. The earlier projects currently being constructed should have little reason to fear given their head-start, however the later Australian projects, planned to come onstream towards the beginning of the coming decade have started to face increasing investor and creditor scepticism in the second half of this year. The cost inflation suffered by projects in

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East Africa

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The first concrete plans for an LNG facility are being drawn up by Anadarko. This is an artist’s rendering of how Anadarko’s offshore Mozambique LNG project could look. KBR provided the concept.

On-the-job education and training will therefore be paramount for oil and gas companies to launch early on. Australia is a key to this, as it is increasingly clear that its LNG exports will have relatively high production costs compared not only to the existing producers and suppliers of the Pacific Basin, but likely to its later East African competition. Should a buyers’ market develop by the time the projects start marketing their initial long-term baseload contracts - the pricing of which will be key to ultimately convincing debt markets - some of those projects might well start to look to financially shaky. The fact that current economic worries over long term demand growth in China and the rest of East Asia persists, is not helping the Australians’ case either. That the Pacific LNG Basin will be the main target for East African gas is however looking quite certain. Mozambique’s distance to large markets like India and East Asia is not dissimilar from Qatar’s. Like the latter, exports to Europe and the odd Latin American buyer on the east coast could well be conceived, however given the US shale gas boom and the increasing likelihood of North American gas exports in the coming decade, such contracts look more like the spicing of a portfolio, rather than the bulk. From a buyer’s perspective several Europeans might welcome the odd contract from East Africa, to diversify their sources, although sluggish demand growth and the likely competition from North America looks unlikely to allow Europe to emerge as a large taker of East Africa’s gas exports over the foreseeable future.

Risk of overheating Still, although Mozambique and its northern neighbours seem to have the upper hand in their estimated project economics, the risk of severe project cost inflation should not be

18 Oil Review Africa Issue Six 2012

underestimated. Several of the reasons behind the heavy cost inflation in Australia has been blamed on the projects’ remote location, expensive logistical and infrastructural solutions as the construction gets underway, as well as a shortage of skilled and unskilled personnel in the vicinity, driving up labour costs considerably. Unfortunately, all of East Africa has the ingredients for project overheating. The lack of infrastructure in the widest sense of the word, as well as skilled personnel, will require the construction of everything from airports to roads and skilled and unskilled worker housing. Moreover, this will happen at the same time as other oil and gas projects get underway, not only in Mozambique and across the border in southern Tanzania, but also in Uganda and soon after in Kenya. This situation has already pressed rig rates upwards and the cost inflation will only spread further into construction and service sectors. The cost of unskilled labour might be what maintains the region’s economic edge compared to for instance West Australia, although it remains to be seen whether enough of the skills and experience needed in the unskilled worker segment can be drummed up. The skill set of Australian construction workers after all remains higher on average to the equivalent East African workforce, particularly when it comes to areas like, for instance, machine operations and quality control. On-the-job education and training will therefore be paramount for oil and gas companies to launch early on, in order to mitigate delays and instil efficient cost controls.

Getting the rules right The smooth development of the offshore deepwater gas reserves is also conditional on the region’s legal and fiscal framework development not creating too much disruption. Recent changes by Mozambique to ensure that its NOC, Empresa Nacional de Hidrocarbonetos (ENH) takes stakes of up to 40 per cent in future projects, after hitherto having taken stakes of only between 1025 per cent. The higher stake is still not

particularly problematic in an international comparison, rather it is more in line with international standards in developing countries with significant natural resources. It does however point to a potential pitfall. It is normal for countries to provide very lax investment terms when looking to attract early exploration into unproven hydrocarbon reserves. As reserves are firmed up and development commitments materialise, it makes sense to tighten terms, since the risk is lower and the reward much more certain. However politically, there is always a contagious risk for populism to creep into these issues and for fiscal demands to escalate until they overshoot and cause investment to freeze. In many ways this could be said to have been the underlying factor in Uganda, although the dispute manifested itself as a deadlock around the tax on a particular transaction. This trend is not at all confined to developing countries, as recent escalating tax demands by the Israeli parliament in the wake of the large East Mediterranean Leviathan gas discovery have shown. Indeed, it would be surprising if some US state legislatures will not in some extent display the same logic as the shale oil boom unfolds amid austerity measures and budget tightening. Still, the less developed the institutional frameworks, the more uncertainty and potential damage these types of debates, if getting out of hand, can make. In Mozambique and Tanzania problems similar to Uganda’s have so far been absent and the relative strength of Tanzania’s central institutions could work in its favour. On the other hand, there has been more of a conscious strategy to foster business friendliness in Mozambique over the last decade, creating a systemic culture more supportive of foreign investments, making much of Tanzania’s institutions look more bureaucratic. Although a pro for Mozambique, this does not have to mean that much in a large-project context, as long as the right signals are sent from the Tanzanian legislature and government. It is after all worth remembering that Uganda until recently was regarded as a very welcoming business destination in the region – a soubriquet it could soon regain, should it manage to put the dispute with Heritage Oil behind itself and reassure markets about its future policies. As 2013 dawns, we should see the concentration in the region steadily start to switch from exploration alone to development and proper project planning. While it is too early for construction to commence, engineering crews are likely to start drawing up plans for pre-FEED and FEED stages. Getting off to a good start will be important and the role played by governments and legislatures throughout the region will be crucial for the projects to be able to know under which rules to calculate their long-term returns. That, as well as the initial approaches by the oil and gas companies to their government relations and labour skills training will be the things to watch in 2013, to know how successful the projects will be in keeping within their schedules and budgets. ■

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East Africa

Oil Review talked to the Hon Kiraitu Murungi, EGH, MP Minister for Energy, when he was in London recently.

Transparency key to Kenya's

energy future T

HROUGHOUT THE CONTINENT, there are an incredible amount of investment opportunities in the oil & gas/energy business. What can you offer that other countries can't? We have a sound legal framework as well as accountability of government behaviour. Well managed oil resources, like other natural resources, will lead to socio-economic transformation and sustainable development in Kenya. In addition, we are business- and investorfriendly with well-established transport and telecommunications infrastructure. Kenya's oil finds may be larger than those found recently in Uganda. But what will oil revenues do to the Kenyan economy, and the political culture? We have a proven record committed to creating prosperity and operating ethnically and transparently. We intend that operations will be led by Kenyans as much as possible. If the recently discovered oil in Kenya is found to be commercially viable, (Kenya has moved a step closer to this, following the discovery of fresh reserves by Tullow Oil) it will significantly raise the investment profile of the country. So that it is of benefit to the whole country, oil revenues need to benefit the poor. How are you hoping to achieve this? The resources will be shared between central and local governments. After first oil, profits will be shared with the Government and NOCS, and the Government will share with the local community. Oil is often called 'The curse of Africa'...One reason is that the money doesn't seem to

trickle down to the people, but just a very small minority; also it is a capital-intensive industry, not a labour-intensive one. What will you do to avoid these problems? We have seen other nations' mistakes - the "curse" is due partly to the non-transparency of former colonialists and now certain African governments. We feel strongly that the oil business is for everyone, not just NCOs and governments. Oil revenues do not necessarily equal national wealth; have you looked at strategies that are aimed at managing petroleum revenues more transparently and effectively so as to capture the benefits of petroleum wealth for current and future generation? for instance public private partnerships? Oil can be a political catalyst to improve infrastructure, education, healthcare and agriculture. We want to change from rain-fed to irrigated agriculture! What is the status of your oil refinery? What steps are you taking to improve its efficiency and bring down costs? And are there plans for further refineries? We are planning a US$1.2bn upgrade and engineering re-design for the refinery in Mombasa, to enhance the plant's crude oil refining capacity and enable it to handle more complex operations. The project will be scheduled for completion over a three-year period. The improved operational efficiency will allow the refinery to blend crude oil from cheaper sources to produce high-grade refined oil. We are also going to establish a refinery in Isiolo and connect it to a pipeline that would supply the refined oil to the rest of the country. There is going to be a pipeline connecting Nakuru

Hon Kiraitu Murungi, EGH, MP Minister for Energy.

We feel strongly that the oil business is for everyone, not just NCOs and governments. to Isiolo, Nakuru to Eldoret and Kisumu and another one connecting Isiolo to Nakuru, Nairobi and Mombasa to feed the local market. Currently all the oil that has been discovered is in the northern Turkana region. Do you have plans to start exploration elsewhere, and if so, where? We have done studies and there are four major sedimentary basins: Lamu, Mandera , bordering Ethiopia and Somalia, Anza and the Tertiary Reef Basin which borders with Tanzania. Technology transfer: What are the rules/laws to ensure that the oil companies train Kenyans to become experts in the oil exploration and production sector? It should take five years to production, during which time Kenyans will go on energy courses at international universities, such as Princeton. We want to make Kenya a role model for best management practices of oil revenues. â&#x2013;

Since this interview the Minister has announced that granting of licences for blocks will in future be made more transparent through competitive bids. The new licences will come with enhanced financial take by the government. His other proposed value addition announced is a target equity participation of 25 per cent in oil production by the government (or its agent).

20 Oil Review Africa Issue Six 2012

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East Africa

Matthew MacLachlan, programme manager, Farnham Castle, reports on how Tullow is trying to build relationships in Uganda.

Tullow Oil:

Working together A

S AN ORGANISATION working with many different nationalities, Africa’s leading independent oil company, Tullow Oil recognises the importance of culture. Farnham Castle has been working with Tullow Oil since February 2010, providing 30 workshops to 200 personnel, on ‘Intercultural Team Working’ in Uganda, Ghana and the UK and “Working with the Chinese in Africa”

The way questions have been formulated during recruitment interviews is important.

Dispelling myths In relation to Uganda, the aim of the training is to dispel myths surrounding Uganda and provide a real educational journey on life in Uganda. “The workshops are an important chance to look at some of the myths and stereotypical perspectives about different cultures, from the point of view of both our expatriate and Ugandan staff,” explained Angela McDonald, HR advisor, Uganda BU, Tullow Oil. “Western staff soon discover Ugandans are highly motivated, frequently working 10-12 hour days and that most of our employees have at least one Masters degree and so are highly skilled.” This can be a very pleasant surprise to those who have succumbed to the stereotypes. Going deeper, beyond initial perceptions is an essential step in working effectively in Uganda. “Misperceptions can create difficulties in building relationships so addressing these misperceptions is crucial and helps put both expatriates and our local staff on an equal level,” continues McDonald. The workshops start with a discussion of the complex administration system in Uganda and the many different tribes, each with their own King or Chief and language, and how this influences the way local people typically behave and work – participants actively contribute with their local knowledge and tips. “The workshops have enabled the groups to discover some unusual facts about themselves that they would otherwise take as normal,” explains Arthur Nsubuga Kironde, training and

22 Oil Review Africa Issue Six 2012

Building Uganda's oil and gas talent pool.

development advisor, Tullow Uganda Operations. “For example, the use of ‘Uglish’ (A Ugandan dialect of English) is common in Ugandan speech but can be misleading to a non-Ugandan.” An example we frequently use to show how language does not always translate with the same meaning across cultures, is the Ugandan compliment: “You have put on weight!” Locals are often surprised to learn this comment is not a compliment in Western cultures.

Misperceptions can create difficulties in building relationships so addressing these [misperceptions] is crucial. In Europe it is important to maintain eye contact and ‘sell yourself’ in a job interview. However, prolonged eye contact in Uganda is seen as rude and aggressive and ‘selling yourself’ means you are ‘full of hot air’. As a result of this insight, the way questions have been formulated during recruitment interviews is important. Instead of asking open, general questions, managers are encouraged to request specific information about particular projects, and reassess attitudes to eye contact. The area of greetings and communal eating are two examples of where specific behavioural changes have been encouraged: sharing food is important to building relationships in Uganda,

and expats are encouraged to forgo sandwiches at their desk. Similarly, in Uganda, if someone is not greeted they are considered unimportant. Expats need to be aware that walking through an office and greeting only the one person they needed to talk to is an issue. Ugandan staff are also encouraged not to take this behaviour personally if it does occur. We therefore focus on reinforcing Tullow values, building new cultural approaches and behaviour. “These workshops are a fascinating journey into the cultures we work with,” explains Angela McDonald. “The programmes are continually updated to address the new challenges we face. In addition, through feedback gained from programme participants, we continue to implement positive changes within our organisation to ensure a respectful and productive working environment for all our staff, from whichever culture they originate.”

Top hints for working in Uganda Top hints for working in Uganda: greet everyone warmly, be sociable and open. Re-evaluate the importance of eye contact. Most of all explore this amazingly beautiful country!

Farnham Castle, a leader in Intercultural Business Skills training, delivers training on any culture or region. Farnham Castle’s comprehensive range of intercultural training provides the skills and understanding required to be more effective in the global business environment. For further information visit www.farnhamcastle.com/intercultural ■

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Inspection company AMOSCO is looking to bring its considerable experience and expertise from working in North, South, and West Africa into East Africa

AMOSCO sets sights on African expansion WITH OVER 30 STRAIGHT years of experience offering oilfield tubular inspection and management, lifting inspection, nondestructive testing, machine shop, and engineering services in a number of countries within North, South, and West Africa, AMOSCO has more know-how when it comes to developing and maintaining a successful oil and gas services enterprise within Africa than most. In response to growing activity and demand, the company is now planning to expand its services offering to potential clients throughout East Africa. “Operating an oil and gas services company in Africa presents unique, and highly frequent, challenges”, says Joe Graham, AMOSCO’s Regional Manager for Africa. “From local content considerations to ever-changing QHSE dynamics to differing client reporting requirements, we have seen – and adapted to – them all. This experience makes us ideally suited to now serve the increasing needs of the oil and gas inspection and inspectionrelated services market in East Africa”. AMOSCO’s longstanding corporate success has been largely due to its sustained service

quality resulting from a high staff retention rate, its responsiveness to client needs, and its competitive pricing strategy – factors that have resulted in high customer retention rates over the years. “Our core company principles – value, consistency, responsiveness, and flexibility – are also our strengths, and continue to bring us, and by extension our clients, success”, points out Graham. “For example, we are continually focused on rapid services expansion to improve potential clients’ operational efficiencies and effectiveness. Most recently, having noted the substantial cost and time savings derived from rope access services versus the traditional scaffolding approach used to inspect hard to access rig areas, we quickly sourced and equipped one of the most well-qualified rope access inspection teams currently in Africa”. AMOSCO’s focus on expanding its footprint has further coincided with a drive to develop both its internal systems and corporate image. In respect of the former, the company is currently conducting a detailed QHSE policy re-structuring under a new Regional QHSE Manager, while with regards to the latter, a new, increasingly functional company website

is in the offing. “It is of paramount importance that we continue to improve and modernise all facets of our business”, concludes Graham. “The changes we are making to the company will significantly enhance our existing operations in Africa, and support the many new operations we intend to establish as we move forward into East Africa”.

In addition to inspection services, AMOSCO provides maintenance and repair services on pipes.

Oil Review Africa Issue Six 2012 23

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East Africa

As East African nations are poised to become the next key oil and gas market, many oil companies are lining up to enter the game – but some industry analysts are sounding a note of caution. Jon Offei Ansah reports.

Experts cautiously optimistic about

East African O&G M

AJOR DISCOVERIES ARE tantalisingly promising, but questions of infrastructure to make them commercially viable, uncertain regulatory environments and the potential for conflict put up plenty of roadblocks. Kenya is East Africa’s largest economy, and a major discovery in March 2012 has set it on the oil map and promises to turn the country into the region’s main energy hub. Unlike its neighbours, Kenya’s capacity for infrastructure development is more ambitious and its plans are feasible, if not perhaps overly optimistic in terms of estimated completion dates. Jen Alic of global intelligence and consulting company, Isa Intel, said, “The oil juniors are having trouble keeping up with their contractual obligations and we’re likely to see some buy-outs and joint ventures in the near future, as Kenya seeks major players who can contribute to its massive infrastructure plans.” Oil companies are still about a year away from determining whether they can extract what they have found and turn it into revenues. But Kenya is confident. This confidence is expressed in the largest African infrastructure project ever – the Lamu Port-South Sudan-Ethiopia Transit corridor (LAPSSET). The corridor includes a new export terminal and refinery at Lamu, a 2,000 km pipeline that hopes to pump oil from South Sudan to Kenya, stopping off for refining in Ethiopia, and a massive highway and network connecting the region. Kenya’s infrastructure plans are impressive and likely to go ahead, but there are still uncertainties as to timing; while the Kenyan government is in talks with China for the construction of the US$1bn LAPSSET highway and rail network, there have been no commitments yet. Meanwhile, Mozambique is likely to offer up some 12 new oil and gas exploration blocks in Q1 2013. Three of those blocks will be in the Rovuma basin, the site of 130 tcf of gas discoveries by Anadarko and Eni. The government estimates there may also be another 150 tcf left to discover. While less impressive than Mozambique’s gas finds, Tanzania’s estimated 33 tcf, boosted by recent offshore discoveries, will place it on East Africa’s gas map nicely. Some industry experts do not however expect any major upsets to development and production, saying it is a ‘good game’ for the juniors. Tanzania has a natural gas processing plant on Songo Songo Island, with a 70mn cfd capacity. It is also planning an LNG terminal. There are however some key points to consider. Tanzania does not have a national gas policy, but authorities are expected to unveil one imminently. There will also be a restructuring of the state-run oil company with an eye to increased regulation of gas discoveries. The plan is to split the body into two parts, including an upstream regulator and a publiclyowned commercial oil company. Opposition politicians are however pushing for a moratorium on new oil and gas exploration licenses until regulations are in place. Meanwhile, the government is hoping to build a new 530km pipeline from Mtwara to Dar es Salaam, which could transport 784mn cfg/bo.

Where to refine Uganda’s oil Uganda discovered 2.5bn bbl of oil in 2006 and announced another one billion barrel discovery in October in three new wells. The country had hoped to begin exporting in 2017, but announced in early November that they were at least a year off from this initial estimate. Alic said, “The authorities are having problems with plans to build a refinery in Hoima, in the west of the country. They cannot get the oil

24 Oil Review Africa Issue Six 2012

Both Mozambique and Tanzania are planning LNG terminals.

Tanzania does not have a national gas policy, but authorities are expected to unveil one imminently. companies on board for the refinery, which is simply too massive a project for Uganda’s reserves, which can be refined elsewhere more cost-effectively. It looks like Uganda is going to scrap the refinery plans and instead build a 1,950km southern pipeline to the Tanzanian port of Dar es Salaam or a 1,325km northern pipeline to Mombasa, where Kenya has a refinery.” Alic also identified Uganda’s new draft oil law as the biggest problem. He said, “[It is] being held up in a government stalemate, divided on how much control the country should maintain over oil companies. Amid these regulatory delays, there is a moratorium on licensing of new exploration blocks, which will further delay production and infrastructure development.” Landlocked South Sudan won some 80 per cent of Sudan’s total oil reserves (about 6.7bn bbl) when it gained independence in July 2011. But for now, production is offline as the new country, locked in a border dispute with Sudan, has no way to export its production. Earlier this year, Juba (South Sudan) and Khartoum (Sudan) threatened to renew bloody conflict over oil transit fees. Juba halted production in January over Khartoum’s tactic of charging prohibitive transit fees. This summer, the two agreed on transit fees, but production will not resume until border disputes over key oil-rich areas are resolved. Juba is stalling in talks because it is hedging its bets that the LAPSSET pipeline will be completed in time to give them more negotiating power. “Neither Juba nor Khartoum can hold out much long without oil revenues, which account for much of their economy. This in turn risks unrest at home,” Alic concluded. ■

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At the recent Africa Oil Week held in Cape Town, Oil Review Africa interviewed Scott Aitken, Co-Chief Executive Officer of Atlantic Energy. Interview

Atlantic Energy

making new strides CAN YOU EXPLAIN the Atlantic Energy Business model? We are an exploration and production company, focussed more on the appraisal and development side of the sector. What we seek to do is find fields where there are opportunities to increase existing reserves. We believe that with modern subsurface studies, we can do more than previous companies on these assets. We are currently focussed on Nigeria and want to grow our production "operating leverage", so are very a much hands-on company. The company was founded in 2010 by a Nigerian, Olajide Omokore, who developed his business in the downstream field. Atlantic Energy is a vehicle for him and other Nigerian business associates getting into upstream. All founders and shareholders are Nigerian so Atlantic Energy is an indigenous company, and, as the shareholders wanted the best management team possible, they brought in talent both from within and outside Nigeria. Can you give us a recap of your activities in 2012? The primary focus during 2012 has mainly been on expanding the management team's operational capacity; we will have grown from a head count of 10 to 100 people within 2012. Secondly, we have been building and implementing the business and operating processes. We have also been understanding the subsurface of the assets we are involved with to enable field development plans to begin in 2013. Our third focus was identifying "quick win" production optimisation opportunities. There are currently hundreds of undeveloped discoveries in Nigeria, most of which are located onshore. All our activities are on onshore and brownfield sites. There are, of course, challenges ranging from 30-year-old oil and gas infrastructure; community stakeholder relationships and expectations as well as working in a swamp and land terrain. However, the solutions to these challenges, respectively, include a detailed evaluation and phased infrastructure replacement/upgrade; community engagement and updated needs assessment and terrain-based asset management. Another challenge of working with multiple partners and a new model can be tackled by project prioritisation and a clear centralised management structure with a focus on strong relationship building which Atlantic Energy is committed to. However, on the whole, we feel that Nigeria has a lot of upside for a company like ours and Atlantic Energy is braced to meet these challenges in 2013 and beyond. What does 2013 have in store for Atlantic? Our Strategic Alliance Agreements (SAAs) with Nigerian Petroleum Development Company (NPDC), a wholly-owned subsidiary of the national oil company, NNPC, covering Oil Mining Leases 26, 30, 34 and 42, will expand as they become operator of two more assets (OMLs 30 and 34 ) having taken over operatorship of the other two assets in early 2012 (OMLs 26 and 42); we will be playing a project management role on one of these. The SAAs are built around Atlantic Energy providing funding and technical assistance including the training of NPDC staff to attain production optimisation from the assets covered by the SAA. We will be assisting NPDC in implementing the programmes and studies prepared in 2012 in the field next year (so far we have only been conducting technical studies and supporting JV partners), so next year we

Scott Aitken, Co-Chief Executive Officer of Atlantic Energy.

will actually begin field work. Do you have a vision? In terms of numbers, we want to build a portfolio of one billion boe (barrels of oil equivalent) and use operating leverage to grow production to 150,000 boe by the end of 2015 through existing assets and the acquisition of new assets. Our current entitlement from the assets is 40,000 boe. With positive cash flows from existing assets, a strong financial base of equity and debt funding entirely raised from leading Nigerian banking institutions, Atlantic Energy is well positioned to play a leading role in the Nigerian independent oil and gas sector. Do you have any plans to go beyond Nigeria's borders? The opportunities within Nigeria are substantial and we want to get to the optimum level in Nigeria before we look overseas. However, diversification is our intention in the medium to long term. Atlantic Energy along with Ozwald Boateng recently established the 'Made in Africa' Foundation. Can you tell me something about this? The Made in Africa Foundation focuses on supporting and funding power and infrastructure projects that would not get off the ground without such support. The Foundation will provide the support necessary by funding feasibility studies as well as developing the management teams and business plans. Atlantic Energy has initiated our commitment to this foundation with over US$6mn which includes three years of costs and underwriting two projects in the 18 months and subsequently, Atlantic Energy intends to underwrite one project per year. â&#x2013;

Oil Review Africa Issue Six 2012 25

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Ghana

Efforts by the Ghana government to commence the delivery of gas in December 2012 (ostensibly to win votes in the December 7 general elections) have been hampered by delays due to some challenges facing the implementing agency, the Ghana Gas Company (GGC). Jon Offei-Ansah reports.

Ghana’s gas

project I

N ALL LIKELIHOOD, gas from the Jubilee Field will not be forthcoming this year. According to GGC chief executive, Sipa Yankey, the late release of a 15 per cent payment obligation by the ministry of finance to the project contactors led to a period of stalemate on the progress of work. In addition, heavy rains recorded in the western region, the project region, and the issue of land acquisition on the right of way of the project have all led to some delays that could affect meeting the December 2012 deadline set by the company to start delivery of gas from the Jubilee Field. ‘The delay could shift the project completion to next year, but we have adopted some preventive measures to forestall further delays,’ he said. The delays notwithstanding, Yankey is confident that the company is making significant inroads into completing the project on time. On progress made so far, Sipa Yankey said the offshore pipes, which arrived on September 21 at the Takoradi port, have been conveyed in batches to site and that the pipe-laying ship has also been arranged. He also noted that earth and civil work at the site for the gas processing plant is in progress. On some pragmatic initiatives by the company to meet deadlines despite the delays, Yankey said his outfit has increased the work force for laying the pipe lines and doing some of the work in parallel to increase output. ‘We are determined to complete mechanical integration works by early December,’ he assured.

Many challenges Ghana's quest to build its gas processing infrastructure following the discovery of commercial quantities of oil in the Jubilee Fields in 2007 has been met with lots of challenges and mired in controversy. When the Ghana Gas Company first announced its ambitious plan to complete the first phase of a gas processing plant by December 2012, not only did some experts in the industry doubt GGC’s ability to deliver on this promise, but also raised questions on the quality of plant Ghana stands to get within the ambitious time. China’s Sinopec, which is spearheading the gas process in the country, delivered some bad news to the government recently when it discovered upon delivery of pipes manufactured by a Chinese firm to connect the Jubilee Field to land that they lacked the coating that would allow for the most effective flow of gas. With no local company equipped to correct this anomaly, Sinopec and GGC have to bring in companies from Nigeria. According to reliable sources, when the contract was put out to tender for

26 Oil Review Africa Issue Six 2012

The offshore pipes have been conveyed in batches to site and the pipe-laying ship has also been arranged.

The Ghana Gas Company explains that time is of the essence. the construction of the pipes, the specifications provided by Sinopec were so inaptly described that some companies withdrew their bids, leaving the job to Chinese companies. Other concerns raised by some industry experts and sources close to the project indicate that Ghana opted for a plant with a 46 per cent liquid recovery rate, to one which has a recovery rate of 85 per cent, and which could yield an additional 30,000 barrels of gas per day, amounting to over US$100mn a year. The GCC has also been compelled to publicly refute speculation that the total project cost has been inflated by Sinopec. According to Sipa Yankey, due diligence conducted by the company has saved the country about US$250mn. ‘The costing of our project is based on so many factors - similar projects worldwide and our intimate knowledge of the prices of various components. Luckily we have expertise from some of our colleagues at the West Africa Gas Pipeline who have just finished a project, and they are familiar with all these. So our cost for the project was heavily influenced by the experienced and knowledge of some of our staff,’ he said. Yankey explained that Sinopec had costed the project at US$998mn, but ‘because of our

knowledge of the market and some of our experts’ experience, and through negotiations, we were able to bring it down to US$750mn, saving the country US$200mn. Additionally, this particular price has been frozen, which means Sinopec cannot inflate, over-invoice or under-invoice. So Ghana government is adequately protected,’ he added. Experts indicate that the only excuse used to get Ghana to accept the plant under construction is that it would need an additional 40 days to complete. But the Ghana Gas Company explains that time is of the essence, considering the fact the oil wells stand the risk of collapsing if the gas was not extracted. Ghana was due to start producing gas in 2011 to feed the national electricity grid and halt the rampant power outages in the country. But it is now all but certain that will not happen before 2013, to the displeasure of the government who hoped to use it to woo the electorate. The problem has been compounded by a recent halt to gas deliveries to the Takoradi and Tema power stations by the West African Gas Pipeline after a vessel broke the pipeline offshore neighbouring Togo. As a result, Ghana’s great expectations for its oil and gas have so far proved disappointing. Two years after oil production began on Jubilee, the flow remains well below the projected 120,000 bpd. During the first half of this year it averaged just 63,000 bpd. Although work has begun on wells to push the total to 86,000, the field will not hit its peak of 120,000 bpd before next year. ■

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Geology

S07 ORA 6 2012 Geology_Layout 1 12/12/2012 15:54 Page 28

TGS begins seismic sweep of Angolan pre-salt

NORWAY'S TGS HAS begun an extended 3D shoot covering 4,064 sq km of a pair of pre-salt blocks off Angola operated by US supermajor ConocoPhillips. The industry-funded supported shoot is an addition to the 12,500sq km multi-client 3D shoot off Angola which has finished the acquisition stage. TGS’s senior vice president for the eastern hemisphere Stein Ove Isaksen commented that Angola’s conjugate margin pre-salt basins were causing excitement because they offered potential opportunities similar to hydrocarbon-rich basins off Brazil. The Geco Eagle is acquiring the seismic data to be processed by TGS and with preliminary data to be available from the fourth quarter of next year. ConocoPhillips holds a 30 per cent operatorship stake in both blocks awarded last December, with Angolan state player Sonangol on 50 per cent and Chinese-Angolan venture China Sonangol International (CSI) on 20 per cent.

Chariot kicks off Mauritania 3D shoot AFRICA-FOCUSED EXPLORER Chariot Oil & Gas has kicked off a 3D seismic survey over Block C19, off Mauritania. Chariot has contracted Norway’s Fugro to carry out the 3500 sq km shoot to identify structural and stratigraphic traps within Block C19. The survey will be carried out in water depths ranging from 30 m up to 2000 m and is expected to take about 90 days to complete. Once completed, it will fulfill Chariot’s initial three year work commitment on the block and will then be interpreted to define drillable prospects. Chariot holds a 90 per cent operated interest in Block C19, with Mauritania’s state-owned oil company Société Mauritanienne de Hydrocarbures holding the remaining 10 per cent.

Dolphin lines up northwest Africa 3D shoot NORWAY’S DOLPHIN GEOPHYSICAL has said it has secured a letter of intent for a 10-week 3D seismic survey off northwest Africa. The Bergen-based contractor said the Artemis Arctic would carry out the survey. The identity of the client was not disclosed, but Dolphin Geophysical said that the Artemis Arctic would acquire the data “in direct continuation of the current contract”. The Artemis Arctic has most recently been tasked with acquiring data off Colombia for India's Oil and Natural Gas Corporation (ONGC) in a contract due to finish at the end of this month. Africa bound: Artemis Arctic hired for northwestern shoot.

Vanoil concludes seismic survey in Kenya VANOIL ENERGY HAS completed a 100-sq km 3D seismic and gravity survey over its western leads in block 3A in Kenya. This is the first 3D seismic survey ever completed onshore in Kenya and it complements the 845 km of 2D seismic acquired by Vanoil in previous years. A suite of substantial drilling targets have been defined on block 3A within the surveyed area and Vanoil plans to select its first two well locations by the end of November. Vanoil has furthermore signed a contract with Sinopec to secure the last available onshore drilling rig in Kenya. The rig is stacked in Nairobi and ready for mobilisation. Vanoil's contract includes two firm wells and an option for two more. With its seismic surveys completed and a drilling rig in place, Vanoil is on track to spud its first well in 1Q 2013. "Vanoil has completed a comprehensive exploration programme in Kenya, using 3D seismic and the latest interpretation techniques to produce robust drilling targets. Securing the last available onshore rig in Kenya allowed Vanoil to avoid substantial mobilisation fees and to be ready for its first well in 1Q 2013," Aaron D'Este, CEO of Vanoil, commented.

PGS to shoot Namibian seismic PETROLEUM GEO-SERVICES (PGS) has signed an agreement with the National Petroleum Corporation of Namibia Ltd (NAMCOR), for the acquisition of both 2D and 3D MultiClient seismic offshore Namibia. Under the 10 year agreement, PGS will begin its operations with the acquisition of a large 2D regional survey during Q1 2013 over the open deep-water blocks. These blocks will form the basis of a future Licensing Round and the PGS survey will be the primary technical dataset for that Round. PGS will be utilising the latest GeoStreamer® dual sensor technology on this survey, which runs the entire length of the Namibian offshore, from the Angolan border in the north to the South African border in the south. The agreement also provides PGS with the rights to acquire 3D MultiClient surveys. “PGS is excited to be bringing GeoStreamer technology into Namibia and we very much look forward to working with the Ministry and NAMCOR to maximise the full exploration potential offshore Namibia” said Mike Johnson, VP Business Development, Africa & Middle East MultiClient. “GeoStreamer offers clear and proven operational advantages, and dual sensor technology will provide explorationists with the clearest

28 Oil Review Africa Issue Six 2012

ever 2D and 3D imaging of the subtle stratigraphic traps that are key to unlocking Namibia’s full offshore hydrocarbon potential“.

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Gas

Mozambique may justify 8 LNG trains US-BASED ANADARKO Petroleum said that continuing exploration successes offshore Mozambique may justify expanding a proposed LNG development to eight LNG trains from an initial plan for two five million mt/year plants, vice president for exploration Frank Patterson has said. Speaking to delegates at the Africa Oil Week conference in Cape Town, Patterson said the Golfinho discovery now holds as much as the earlier Prosperidade discovery, taking total recoverable reserves of gas in the Rovuma Basin block to over 60 tcf. With more discoveries being developed, Patterson said much larger scale exports could be possible. "The two train development is just the beginning. We think there could be as many as eight," Patterson said. Production off Mozambique will begin in 2018, Patterson said. The Anadarko discovery is located close to another huge reserve found by Eni, which holds an estimated 70 tcf, of which 50 tcf are part of the same geological structure as the Anadarko discovery. With the discoveries by both companies in close proximity, the impetus is on collaboration in order to reduce costs. Eni's exploration head Roberto Casula recently said a unitisation deal is a "key trigger" for the development plan, adding that the company expects to finalise a deal with Anadarko "in the coming months". While both blocks boast sufficient gas reserves on their own to justify a standalone LNG plant, combining resources would beef up commercial viability significantly.

Important new discoveries in Mozambique ENI HAS ANNOUNCED new natural gas discoveries within the Mamba Complex, in Area 4, offshore Mozambique, at the Mamba South 2 and Coral 2 delineation wells, which are respectively the sixth and seventh wells drilled back to back in Area 4. The new discoveries add six tcf of gas in place to Area 4, confirming at least 68 tcf of gas in place already discovered. The resources exclusively located in Area 4 are now estimated at about 23 tcf plus of gas in place and the full potential of Mamba Complex at 75 tcf of gas in place and will be assessed with the coming delineation wells. Mamba South 2 was drilled in 1,918 m of water and reached total depth of 4,300 m. The well is located approximately 9 km east of Mamba South 1 and approximately 50 km off the Capo Delgado coast. The well encountered 60 m of gas pay in high quality Oligocene reservoirs. The discovery proved the existence of hydraulic communication with the same reservoir of Mamba South 1. The well flowed lean gas with excellent test parameters which led to the estimation of a sustained production rate of 140mn scfd. Coral 2 was drilled in 1,950 m of water and reached a total depth of 4,725 m. The well is located approximately 15 km north west of Coral 1 and approximately 50 km off the Capo Delgado coast. The well

30 Oil Review Africa Issue Six 2012

encountered 140 m of gas pay in good quality Eocene reservoirs. The discovery proved the existence of hydraulic communication with the same reservoir of Coral 1. Eni is currently planning a production test in the Coral 2 discovery. Eni plans to drill at least two further delineation wells back-toback, Coral 3 and Mamba South 3, in order to assess the full potential of the Mamba Complex discoveries. These last successes further strengthen the potential of Area 4 on which Eni is studying the development plans of this huge gas reserve base. Eni is the operator of Area 4 with a 70% participating interest. The other partners of the joint venture are Galp Energia (10%), KOGAS (10%) and ENH (10%, carried through the exploration phase).

Growing role for Africa in the “Golden Age of Gas” WITH OPEN ACCESS and attractive leasing terms, Africa’s oil and natural gas resources continue to attract a broad spectrum of investors, according to a new report from Ernst & Young, Natural gas in Natural gas discoveries put east Africa on the Africa – The frontiers of world energy map. the Golden Age, launched at Africa Oil & Gas Week. Elias Pungong, Ernst & Young’s Oil & Gas Leader for Africa says, “Natural gas development holds tremendous opportunity for Africa. It can be a primary driver of economic growth and broader social development, as well as a major spur for local employment growth and infrastructure development.” The big future for African gas lies in the East of Africa. The report spotlights Africa’s rapidly evolving natural gas sector, and while Algeria, Nigeria, Egypt and Libya are identified as holding significant reserves, the production of gas is considerably lower in these countries. More recently, the sector’s growth has been concentrated in West Africa, with the huge associated gas resources that accompanied the deepwater oil boom, led by Nigeria and Angola. While the West African gas growth will continue as flaring is reduced and local gas infrastructure is developed, the big future for African gas lies in the East of Africa with the massive offshore gas discoveries in East Africa, particularly in Mozambique and Tanzania. Pungong comments: “While the risk rankings overall in Africa are quite high, for many countries the “risk trend” is improving. Most importantly though, the opportunities for Africa in this sector are enormous and the challenges and risks can be addressed and mitigated.” Africa’s gas reserves will be more than just headline opportunities for the national oil companies (NOCs), the deep-pocketed oil and gas majors, their big international exploration and production (E&P) counterparts as well as well-known African oil and gas specialists. The ramp-up in E&P activity brings opportunity for the oilfield services (OFS) segment, but again, not just for the big international OFS players, but also for local and regional companies that can contribute to the supply chains and to the associated upstream support infrastructure. The broader infrastructure build-out could also include massive export facilities, as in the case of liquefied natural gas (LNG), but also smaller projects such as pipelines and gas distribution networks to support local/regional domestic gas demand. The associated development or expansion of a domestic gas demand sector could also bring substantial commercial opportunities in the power generation, industrial and even transportation sectors. Indeed, many of the gas flaring reduction efforts are tied to domestic gas use projects. Pungong concludes, “African governments and regional NGOs will of course have critical roles to play – first and foremost, developing a meaningful and practical master gas development plan, one that addresses the upstream tax and licensing models, as well as the necessary infrastructure issues and investments, and local training and job creation issues. Collaboration and partnerships with the IOCs, both big and small, will likewise be critical.”

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WITH A MULTIBILLION-DOLLAR gas export terminal under construction in the US, veteran consulting engineer and industry stalwart John Bewsey predicts a worldwide drop in gas prices in the next three to five years, as an increasing number of companies file for export permits. Once some of these permits are awarded, and the gas export terminals are planned, approved and constructed, low-cost gas will eventually filter through from the US to the rest of the world. He says this will have a significant effect on the African gas market, which is growing rapidly, as a result of new findings across the continent. Advanced hydraulic fracturing (fracking) in North America has, in recent years, overturned the US energy market, causing the gas price to drop from over US$10/GJ to about US$2/GJ or less. This has yet to affect the global gas market, owing to logistics, which has made it difficult for the US to export the gas directly. Bewsey says that, if his predictions are proved correct, the impact on Africa’s future in the gas market will be positive, and the bulk of Africa’s power will be reasonably inexpensive and ecologically acceptable. He suspects that, in the long term, Stateowned power utility Eskom will switch to gas because of the significant drop in the gas price once there is a worldwide oversupply, which is likely according to his predictions. Bewsey is hopeful that the Inga water project – a joint venture between South Africa and the Democratic Republic of Congo (DRC), which could produce hydroelectric power for the DRC and surrounding countries – will also be under way by that time. “This means that the bulk of Africa’s power will be reasonably inexpensive and ecologically acceptable,” he says.

Cogaz to supply LNG to CEB WEST AFRICAN ENERGY development company Sasol has signed a memorandum of understanding for its recently formed joint venture with Benin’s BenGaz to supply gas to Communauté Eléctrique du Benin (CEB). London-listed Gasol recently formed a joint venture with BenGaz, named Cogaz, to develop gas distribution infrastructure and supply in Benin. Gasol said it was working to station a floating storage regasification unit in the harbour at the city of Cotonou in Benin. The unit will be used to supply liquefied natural gas to customers in Benin and Togo, including CEB which is the electric authority for both countries. Gasol added it would now work with CEB to finalise the terms of a gas sales agreement with the company.

Oil Review Africa Issue Six 2012 31

Gas

Impact of US shale gas revolution on Africa

E&P

S09 ORA 6 2012 E & P_Layout 1 12/12/2012 15:58 Page 32

ADX agrees further farm out of Chorbane ALPINE OIL & GAS, a whollyowned subsidiary of ADX Energy, has announced it will farm out 15 per cent of its interest in the Chorbane field onshore Tunisia to Rift Basin International Although the agreement is subject to a number of terms and conditions, Rift Basin has made a good faith payment to ADX of US$100,000. Both parties have agreed that the letter of intent will terminate on 15 December 2012 unless earlier superseded by the definitive agreement. Rift Basinâ&#x20AC;&#x2122;s strategic partner, Gulfsands Petroleum, is also set to acquire an additional 30 per cent participating interest in the Chorbane permit. The company will therefore hold a 70 per cent participating interest and will become operator of the joint venture. As operator, Gulfsands intends to embark on a seismic programme in 2013, estimated to cost approximately US$2mn. Following processing and evaluation of the data, the company is expected to drill at least one well on the Chorbane permit during 2014.

PTTEP, partners find new oil field in Algeria PTTEP AND ITS partners have discovered a new oil field from the 6th exploration well Mouia Aissa-1 (MAS-1) drilled in Hassi Bir Rekaiz Permits, Algeria. The well was drilled to a total depth of 3,844 m on November 11, 2012 and yielded the petroleum discovery in formation of Triassic Argilo Greseux InfĂŠrieur (TAG-I) reservoir. The flow test (Drill Stem Test - DST) was conducted and discovered the crude oil flow at approximately 5,243 bpd and natural gas flow at approximately five million standard cubic feet per day (MMSCFD) - the highest flow rate that has ever been discovered in Hassi Bir Rekaiz Permits. PTTEP and its partners have planned in the 1st exploration phase of Hassi Bir Rekaiz Permits to drill nine exploration wells during late 2011 to early 2013. At present, six exploration wells have been drilled with five successful wells. PTTEP and its partners are now in the process of flow testing the seventh exploration well. Hassi Bir Rekaiz Permit is located onshore in the Eastern part of Algeria. It covers an area of 5,378 sq km. PTTEP is the operator with 24.5 per cent interest. Its joint venture partners of this project comprise of SONATRACH (the Algerian National Oil and Gas Company) with 51per cent interest and CNOOC Limited (China's largest producer of offshore crude oil and natural gas) with 24.5 per cent interest. Apart from Hassi Bir Rekaiz, PTTEP also jointly operates the onshore exploration blocks 433a & 416b in Algeria, which are currently under the development phase.

Eni resumes exploration onshore Libya ITALY'S ENI HAS restarted its onshore exploration activities in Libya by drilling well A1-108/4 in the Sirte Basin and some 298 km south of Benghazi.

The well, operated by Eni North Africa, will be drilled to a total depth of 4,500 m and will test a new geological play in EPSA IV 2008 Contract Area A. Eni said that the exploration well is the first of an onshore drilling programme set to continue into 2013, and it marks another step in resuming all of Eni's exploration and production activities in Libya. Eni has already resumed production in Libya, being the first international company to do so in September 2011 at the Abu Attifel field. Libya saw widespread unrest last year as the previous Gaddafi regime was toppled in a civil war.

Galp Energie enters farm-in offshore Morocco GALP ENERGIE HAS entered into a farm-in agreement with the Australian company, Tangiers Petroleum, for the acquisition of a 50 per cent stake in the Tarfaya Offshore area, comprising eight exploration permits, known as Tarfaya Offshore I to VIII, located on the Atlantic Margin, offshore Morocco. Upon completion of the agreement, Galp Energia will be the operator of the Tarfaya Offshore area, a role that until now has been fulfilled by Tangiers. The Tarfaya Offshore area is predominantly in water depths of less than 200 m and covering an area of 11,281 sq km. After finalisation of this agreement, Tangiers will hold a stake of 25 per cent, and the Office National des Hydrocarbures et des Mines,

32 Oil Review Africa Issue Six 2012

(ONHYM), the Moroccan state company, will maintain a 25 per cent stake in the Tarfaya Offshore area. Under the terms of this agreement, Galp Energia will pay in exchange for its 50 per cent interest around US$41mn which corresponds to past costs and to the cost of the first exploration well, limited by a cap, to be drilled within the Tarfaya Offshore area. The Tarfaya Offshore permits are located in an under-explored area and within a proven petroleum system, containing multiple prospects and leads within Jurassic and Cretaceous sediments, as well as emerging potential within the Tertiary and Triassic formations. The already identified prospects in the Tarfaya Offshore Area

include Assaka, Trident, Tarfaya Marin-A (TMA) and La Dam. The exploration programme is expected to comprise the drilling of an exploration well, before mid 2014 in the Trident prospect. According to Galp Energia's internal estimate of volumes and risk, the Trident prospect, which corresponds to the primary target is an oil prone prospect and has estimated gross recoverable exploration resources of 450mn barrels (mean unrisked estimate) with a POS of 21 per cent. It should be highlighted that further resource upside potential remains in the Assaka, TMA and La Dam prospects. The transaction is subject to the required regulatory approvals, namely the approval of the Moroccan government.

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Genel wraps up Somaliland farm-in

THE GOVERNMENT OF Somaliland has given the green light for Genel Energy to take a 50 per cent operated stake in the Odwayne production sharing contract. Genel entered the farm-in agreement earlier this month with Australia’s Jacka Resources which will see the London-listed company fund the exploration programme over the Odwayne Block, including the acquisition of 500 km of 2D seismic and the drilling of one well. Tendering for the 2D seismic contract is scheduled to start during the first quarter of next year. Jacka said the total cost of the work programme for the third and fourth exploration phases of the PSC was estimated at about US$50mn. “All the parties are very pleased with the early approvals of the transaction by the government of Somaliland which allows for a quick and smooth transition of the operator role to Genel,” Jacka chairman Scott Spencer said. He added that work on the exploration programme had started, with an airborne gravity and magnetic survey already underway which will be completed by Genel. The completion of the farmin will see Jacka’s stake in the Odwayne PSC reduced to 30 per cent while Petrosoma’s 20 per cent equity remains unchanged at 20 per cent. The Odewayne Block covers about 22,000 sq km in the south-west of Somaliland, directly to the west of Block SL10B/SL13 which Genel also recently farmed in to.

34 Oil Review Africa Issue Six 2012

Tullow makes another Kenyan hit TULLOW OIL HAS made an oil discovery with its onshore Twiga South-1 exploration well on Block 13T in Kenya. The well was drilled to a total depth of 2350 m and encountered 30 m of net oil pay, with an API greater than 30°, in three sandstone reservoir zones. It also intersected a tight fractured rock section below 2272 m which Tullow said had hydrocarbon shows over a gross 796 m interval, adding movable oil was also successfully sampled from this section. According to Tullow, the tight fractured rock section is a new play type for the region but would need further evaluation to fully understand its extent and any productive potential. Twiga South-1 follows on from Tullow’s successful Ngamia-1 discovery which intersected about 143 m of net pay earlier this year, about 22 km to the south of Twiga South-1. While at first glance the results of Twiga South-1 may seem disappointing, when compared to the Ngamia-1 discovery, Barclays Capital noted that the well targeted a deeper part of the prospect, rather than the most prolific up-dip section as was the case for Ngamia-1. “In other words this well has effectively tested the extent of the reservoir and allows Tullow to better understand the

stratigraphy of the entire basin,” the international investment bank said in its reaction to the discovery. “This should therefore be seen as a positive result with the potential to increase resource estimates for the entire basin.” Financial services firm Morgan Stanley also viewed the well results favourably noting that Twiga South-1 was drilled about four kilometres away from the basin bounding fault to provide insight of the deeper reservoir sections, whereas Ngamia-1 was only drilled two kilometres from the basin fault to prove the play and maximize the reservoir section intercepted. As a result, Morgan Stanley said the Twiga South-1 only clipped the reservoir, with the up-dip potential of the discovery to be appraised later. It added that it believed the discovery of a thick reservoir section about four kilometres from the basin fault with updip potential was “very encouraging” and further de-risked the follow-on prospectivity. Tullow now plans to carry out a series of flow tests on Twiga South-1 over the next four to eight weeks before the rig is moved back to the Ngamia-1 site.

Griffiths spuds 1st Badila well in Chad GRIFFITHS ENERGY INTERNATIONAL Inc has commenced drilling operations in southern Chad, spudding the first development well in the Badila Field. "The spudding of this development well follows a thorough testing programme undertaken earlier this year," said Gary Guidry, President and CEO of Griffiths Energy. "We look forward to announcing the results as and when is practicable." During 2013 Griffiths intends to simultaneously develop not only the Badila Field but also the nearby Mangara field. The company will be drilling two new wells and recompleting Badila-1 before moving the drilling rig to the Mangara Field to commence development drilling there. The Badila Field is approximately 17 km from an export pipeline to the Atlantic Ocean and the Mangara field is approximately 120 km from the same pipeline. Griffiths is currently building a pipeline connection from both fields to the export pipeline and expects to complete the tie-in early in 2013. Both the Badila Field and the Mangara Field are located on Griffiths' DOI/DOB block, which covers an area of approximately 2,744 sq km in the southwestern region of Chad. The newly-spudded well, named Badila-2, is expected to be drilled to a depth of 2,100 m and is targeting Lower Cretaceous sandstone reservoirs. As the first development well in the field, the company has an extensive coring, logging and flow testing programme with results expected during first quarter of 2013. After in-depth analysis of the available information on the Badila-1 well, Griffiths concluded Badila-1 was a potential discovery with an estimated 123 m of net oil pay in the Lower Cretaceous (C and D sands).

Gabon plans offshore licensing round for 2013 GABON PLANS TO launch a new deep offshore oil licensing round in June, providing new investor-friendly regulations can be enacted by then, according to energy minister, Etienne Ngoubou. He told Reuters that Gabon had been pumping at least 225,000 bpd of crude oil this year and is expected to increase output slightly to around 230,000 bpd next year and in 2014. "We postponed the tender of new deep offshore (areas) because we would like to have new regulations first," Ngoubou said on the sidelines of a conference in London. "I hope to get the new regulations by June next year. Gabon has the seventh biggest oil reserves in Africa, BP data show, and the country expects to build on this. "We have had average daily production of 225,000 bpd (this year)," Ngoubou said. "For 2013 and 2014

we will be able to maintain 230,000 bpd." Crude oil exports would be around 12mn tonnes this year: "That will be approximately the same next year and for 2014 also," the minister said. Several foreign oil companies are already operating in Gabon, including Total. Royal Dutch Shell agreed in July a joint venture with two Chinese state-run companies including CNOOC to explore for oil in the country. "We already have three companies which plan to develop some exploration activity next year in three areas. It's Shell, Total and (independent producer) Perenco," he said. The minister said Gabon wished to include local content in its key industries, particularly for nonspecialist areas.

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HRT ups Namibia offshore O&G estimates BRAZILIAN INDEPENDENT HRT has raised its estimated oil and equivalent natural gas in four offshore exploration blocks in Namibia by 457mn barrels. Reuters reported the Rio de Janeiro-based company as saying that it had 7.39bn barrels of "mean potential prospective resources" in the blocks, according to an assessment made by US oil consulting group DeGolyer & MacNaughton (D&M) based on 3D seismic data. The estimate is 6.6 per cent greater than that in a previous D&M study, HRT said. The company said that it had signed a contract to sell part of the Namibian assets to an unnamed company. It planned to start drilling in the region in the first quarter of 2013 after the delivery of a Transocean oil rig. None of the oil and gas in Namibia has been proven and if it exists, it will require significant exploration work before HRT could consider declaring any oil or gas found commercially viable reserves, Reuters stated. D&M estimated that about 5.1bn barrels, or 69 per cent of the potential Namibian resources, were oil and natural gas condensates and 2.28bn barrels were natural gas. When natural gas and oil resources from HRT assets in the Solimões basin in Brazil's Amazon are added, the company has mean potential prospective resources of 7.8bn barrels of oil equivalent, HRT said. The Amazon assets are part owned by Anglo-Russian oil company TNK-BP.

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36 Oil Review Africa Issue Six 2012

Tullow agrees farm-in to Guinea concession HYPERDYNAMICS CORPORATION ANNOUNCED that its wholly owned subsidiary, SCS Corporation Ltd, has entered into an agreement with Tullow Guinea Ltd, a subsidiary of Tullow Oil plc, for the sale of a 40 per cent gross interest in Hyperdynamics' oil and gas exploration concession offshore Guinea and the transfer of operatorship to Tullow. Subject to the completion of due diligence, the sale is expected to close by year-end following the satisfaction of certain closing conditions and approval of the assignment by Guinea's Ministry of Mines and Geology. At closing, the interests of SCS, Tullow and Dana Petroleum E&P Limited in the concession will be 37 per cent, 40 per cent and 23 per cent, respectively. The parties intend to commence drilling a well to test a deepwater fan prospect in the concession no later than April 1, 2014. According to the terms of the agreement, Tullow will reimburse SCS in respect of its past costs in the amount of US$27mn cash at closing and will carry SCS' participating interests share of future expenses up to a gross expenditure cap of US$100mn, from the date of entry into the next exploration period until 90 days after the drilling of the well. Tullow will also carry SCS's share of costs associated with an appraisal well of the initial exploration well, if drilled, subject to an additional gross expenditure cap of US$100mn. "We are delighted to have reached this agreement with Tullow," said Ray Leonard, Hyperdynamics President and Chief Executive Officer. "Tullow fulfills all the requirements we were looking for: expertise and exploration success in the Atlantic Margin off West Africa — particularly the Transform Margin play that is present on the Guinea acreage — along with experience in deepwater production, the financial strength needed to explore this large block and availability of a suitable rig to initiate the deepwater drilling. Our decision to choose Tullow was made in consultation with the Guinea Ministry of Mines and Geology.

Chevron lines up Pacific Drilling rig for West African ops PACIFIC DRILLING‘S ULTRAdeepwater drillship the Pacific Khamsin (UDW drillship) has been awarded a contract by a whollyowned indirect subsidiary of Chevron Corporation for operations in West Africa. The minimum duration of the contract is for an initial two-year term, with contract commencement expected by end of the third quarter of 2013. The contract provides for an option, to be exercised at the client's discretion prior to shipyard delivery of the drillship, which could result in an additional year of contract term. Estimated maximum contract revenues related to the initial two-year term, including mobilisation and demobilisation, are expected to be approximately US$527mn, bringing Pacific Drilling's total contract backlog as of 15 November 2012, to approximately US$3.4bn. "We are proud to announce the further expansion of our relationship with subsidiaries of Chevron Corporation to this fourth drillship. This contract exemplifies our commitment to providing quality drilling operations for our clients and allows us to leverage the operations support infrastructure which we have already developed in the region," Pacific Drilling CEO Chris Beckett stated. Pacific Khamsin is scheduled for delivery by Samsung Heavy Industries in Korea in the second quarter of 2013. The drillship will be capable of operating in water depths of up to 3,700 m and drilling wells up to 12,000 m deep.

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Total sells Nigeria oil field to Sinopec for US$2.5bn “The transaction is aligned with Total’s active portfolio management,” Yves-Louis Darricarrere, head of exploration and production, said. This “will allow us to focus our resources on the material growth opportunities in Total’s portfolio.” China’s state-owned oil companies may end up with a 40 per cent holding in the block because Nexen, which has 20 per cent, is subject to a US$17.4 takeover bid from Cnooc The other partners are ExxonMobil and Chevron The Usan field production, where the ramp-up was slower than expected, may reach 140,000 bpd by the end of 2012, Chief Financial Officer Patrick de la Chevardiere said in July. Total expects a peak rate of 180,000 bpd.

Kinetiko spuds second pilot well AUSTRALIAN EXPLORER KINETIKO Energy has spudded a second pilot production well at its Amersfoort coalbed methane project in Mpumalanga province, South Africa. The KA-10PT well is being drilled about eight kilometres from the first pilot well, KA03PTR, to provide further data on the potential gas field at Amersfoot. Kinetiko said the well would be a single or a two-stage completion and is expected to be completed by mid-December.

The company is currently carrying out the first stage of testing at the KA-03PTR well where it has previously reported “substantial” spontaneous gas

flow from the shallower target horizon. Following the completion of the first stage, the well will be deepened from 250 m to about 370 m to test the deeper gassy sandstones and coal measures. The Amersfoot project lies about 250 km east of Johannesburg and is estimated to hold prospective resources of 2.4 tcf of gas in place, with a further 1.5 tcf of upside. Kinetiko operates the project with a 49% stake under an agreement with its South African partner Badimo Gas.

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Oil Review Africa Issue Six 2012 37

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CHINA PETROCHEMICAL CORP, seeking to reverse a decline in oil reserves, will buy a 20 per cent stake in an offshore Nigerian field from French explorer Total SA (FP) for about US$2.5bn. The OML 138 block includes the Usan field, which started output in February, according to Total. The deal, which is expected to complete by the end of the year, will give Sinopec Group, as the state-backed Chinese company is known, 36,000 bpd of oil production when the field reaches maximum output, according to analysts at RBC Capital Markets. The asset accounts for about 10 per cent of Total’s Nigerian output, which averaged 287,000 bpd last year. The sale to Sinopec is part of Total’s plans to complete US$15bn to US$20bn of asset disposals from 2012 to 2014. Total didn’t say which company will assume its role as operator.

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

November 2012 - OIL & GAS THIS MONTH Country ALGERIA ANGOLA CONGO GABON KENYA LIBYA NIGERIA SOUTH AFRICA TUNISIA OTHER Total

Oil 23 7 2 5 0 14 10 0 1 12 74

Gas 13 0 0 0 0 0 2 0 1 0 16

Misc 1 0 0 0 3 0 1 0 2 4 11

LAST MONTH Oil 26 8 4 5 0 12 11 0 1 13 80

Gas 12 0 0 0 0 0 3 0 1 1 17

Misc 1 0 0 0 2 0 1 0 1 2 7

LAST YEAR Oil 21 7 2 6 0 0 14 0 1 9 60

Gas 11 0 0 0 0 0 3 0 1 0 15

Misc 1 0 0 0 1 0 1 0 1 2 6

Source: Baker Hughes

Tullow pay day off Ghana TULLOW OIL HAS made a light oil discovery in its Deepwater Tano licence in Ghana despite failing to hit the main target, while the UK independent has also brought on stream Phase 1A of its Jubilee oilfield off the West African country. The Okure-1 probe failed to strike hydrocarbons in its main objective levels but proved light oil of 40° API in a gross 17-metre pay interval in Turonian-age sandstones within an overlying secondary objective, after being drilled to a total depth of 4,511 m, the London-listed company said. Integration of wireline logs and pressure data has indicated the oil accumulation is not connected to

other hydrocarbon discoveries in the licence area, it added. However, the well report disappointed the market, with Tullow’s shares trading down 4.8 per cent. Investec analyst Stuart Joyner attributed the fall both to the unsuccessful drilling result and some negative perceptions of Tullow’s takeover deal for Spring Energy, according to Reuters. The latest wildcat was the second in a three-well exploration campaign in the licence, with the first,Wawa-1, drilled by the semisubmersible Atwood Hunter, having made an oil and gas discovery earlier this year. The next well to be drilled will be

Sapele-1, adjacent to Tullow’s producing Jubilee field, that is due to be spudded by year-end. The company also said it has started producing from Phase 1A of Jubilee at a rate of 16,500 bpd boosting total output at the field to 90,000 bpd - from the first of five production wells due to be completed by mid-2013. Operator Tullow aims to further increase output this year through acid stimulation work on two Phase 1 wells as well as bring online the second Phase 1A well by year-end. The company is partnered on Jubilee by Kosmos Energy, Anadarko Petroleum, PetroSA and Ghana National Petroleum Corporation.

Lukoil to drill five African wells in 2013 OAO LUKOIL HOLDINGS will drill five wells in Africa next year at a cost of US$600mn, a senior company executive has said on the sidelines of the Energy Intelligence conference in Moscow. Russia's second-largest oil producer will drill three wells in the Côte d’Ivoire, one in Ghana and one in Sierra Leone, said Andrey Kuzyaev, president of Lukoil Overseas. Lukoil has looked abroad to offset declining Russian production in recent years.

Gulfsands ups stakes in Tunisia GULFSANDS PETROLEUM HAS reached an agreement to acquire additional stakes in existing exploration joint ventures in Tunisia and Italy. For a further 30 per cent interest in the Chorbane permit and 10 per cent stakes in the Kerkouane and Pantellaria permits, the company said it would pay a total purchase price of US$1.1mn to its joint venture partners ADX Energy, XState Resources and Verus Investments, as well as about US$415,000 in reimbursement for past costs. In addition, Gulfsands agreed with ADX (the current operator of Chorbane) to fund up to US$600,000 of the latter company’s share of a US$2mn seismic programme to be carried out on the Chorbane permit. Following the completion of the transactions, Gulfsands would become the operator of Chorbane, onshore Tunisia, holding a 70 per cent interest. Its equity in the Kerkouane (offshore Tunisia) and Pantellaria (off southern Italy) blocks would increase to 40 per cent. As a result of the transactions, Xstate and Verus will effectively be bought

38 Oil Review Africa Issue Six 2012

out of the permits, with ADX retaining a 30 per cent stake in Chorbane and 60 per cent in Kerkouane and Pantellaria. Gulfsands chief executive Ric Malcolm said in a statement that the company was “planning for a significant increase in exploration activity during 2013, in order to advance preparations for the drilling of exploration wells on both the onshore and offshore permits during early 2014." Gulfsands said it intended to kick off a seismic programme on Chorbane in the new year. At Pantellaria, it planned to reevaluate existing 2D and 3D seismic data to prepare for a joint venture decision to proceed with the drilling of a commitment well before February 2014. In addition, the company also announced the establishment of an alliance with Rift Basin Resources to pursue further petroleum projects in Tunisia and elsewhere in North Africa and the Middle East. Under the deal, Gulfsands will take a 70 per cent operating interest in any project acquired.

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Cegelec awarded for key commissioning contracts on the Ichthys Project

EGELEC OIL & GAS Services, a Vinci Energies GSS company, has just been awarded two commissioning* contracts on the Ichthys* production and exploitation of liquefied natural gas project (LNG) off the coast of Western Australia. The Ichthys project, estimated at circa US$35bn, has been touted as one of Australia’s most expensive Energy Projects. The scheme will see gas from the Ichthys Field undergo preliminary processing at the offshore central processing facility (CPF). This condensate will be pumped to a floating production, storage and offloading (FPSO) facility anchored nearby. The gas will be transported from the CPF through a subsea pipeline more than 885 km to the onshore LNG processing plant. The Ichthys Project will have an initial production capacity of 8.4mn tonnes of LNG a year and 1.6mn tonnes LPG a year, as well as approximately 100,000 barrels of condensates a day at peak production. Production is scheduled to start at the end of 2016. The three-year contracts will see Cegelec perform pre-commissioning and commissioning engineering of both the CPF and the FPSO, as well as the commissioning execution for each unit, out of the respective Korean Yards. During the execution phase Cegelec will work in integrated teams with each EPCC contractor, providing relevant commissioning expertise to their existing knowledge and therefore combining strengths to reach a common objective of successful delivery of both projects. This attribution not only recognises Cegelec Oil & Gas Services’ international expertise but also its leading position in the commissioning sector. Vinci Energies is one of the Vinci Group’s five business lines. It grew out of the combination of Vinci Energies and Cegelec in 2010, and was broadened by the creation of Vinci Facilities. It operates in 40 countries (20 in Europe) with a workforce of 60,000 employees and generated revenue of US$11.2bn in 2011. Thanks to an exceptionally dense network of 1,500 business

units, Vinci Energies is now among the European leaders in energy services and information technologies.

* Commissioning corresponds to activities involving testing and putting an industrial installation into service

*The Japanese company Inpex holds a 66.07% shareholding in Ichthys in partnership with Total (30%), Tokyo Gas (1.575%), Osaka Gas (1.2%), Chubh Electric (0.735%) and Toho Gas (0.42%).

Downstream

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Downstream split for Libya? LIBYA’S OIL MINISTRY is proposing to separate the OPEC member's exploration and production activities from refining, shaking up the running of its key industry by creating two separate bodies that would be headquartered in Tripoli and Benghazi, according to a report. In a move that could be seen as appeasing calls for more authority in the oil-rich east, new Oil Minister Abdelbari al-Arusi said the ministry was proposing to set up a body dealing with Libya's oil refining and petrochemicals in Benghazi, Reuters reported. Carving up the responsibilities of the Tripoli-based National Oil Corporation, the capital would be the headquarters for a separate exploration and production body. "In the oil and gas ministry, we have a near-term plan with respect to the (eastern) region," Arusi said after a recent visit to oilfields in the east and a meeting with Benghazi's local council. "(The body) will be called 'The National Corporation for Oil Refining and Petrochemicals Industry' and will oversee all companies operating in this area. It will launch projects and secure funding for them." The NOC website quoted him as saying it would have a branch in western Libya. The Tripoli-based 'National Corporation for the Exploration and Production of Oil and Gas' would have a branch in Benghazi, he said. "These two bodies will be under the ministry," he said. The proposal comes after the NOC reviewed a plan for a Benghazi branch as officials contended with opposition by NOC staff in Tripoli versus protests and threats of output cuts by workers in the east who want more control there.

r r r

40 Oil Review Africa Issue Six 2012

Wentworth pushes ahead with Mnazi Bay WENTWORTH RESOURCES HAS started construction of a pipeline connecting to its Mnazi Bay project off Tanzania while preparing to award a 3D seismic contract for the block. The company said Tanzania’s President Jaykaya Kikwete has laid the foundation stone at the Kinyerezi gas receiving station, signifying the start of construction of the Mnazi Bay to Dar es Salaam gas pipeline project. The 532-km pipeline and its associated facilities are scheduled for completion in the next 18 months. Wentworth executive chairman Bob McBean said the start of the pipeline project marked a new era for the Mnazi Bay concession and its partners. “We are preparing our existing gas wells for full production into the pipeline and we are committed to proving up or otherwise discovering additional resources for incremental production,” he said. In addition, the project partners are preparing to award a contract to acquire about 210 sq km of offshore 3D seismic data over the block. Wentworth said the programme should begin before the end of the year. It is expected to be used to plan upcoming development and exploration drilling. “Acquiring new 3D seismic offshore Mnazi Bay is a logical first step in identifying our next drilling targets,” McBean said. The 756-sq km Mnazi Bay concession lies in the Ruvuma basin in coastal, south-eastern Tanzania, between Aminex’s Ruvuma concession and BG Group’s offshore Block 1. The block contains two discovered Tertiary-aged gas fields, Mnazi Bay and Msimbati. The Mnazi Bay partners comprise Wentworth, Maurel et Prom and the stateowned Tanzania Petroleum Development Corporation (TPDC). The partners are currently finalising a gas sales agreement to supply 80 mmcfd of gas to the pipeline. The TPDC has now asked to increase this amount to 200 mmcfd as soon as possible.

S11 ORA 6 2012 Technology_Layout 1 12/12/2012 16:44 Page 41

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Technology

The growing potential of digital gas lift in African operations, particularly offshore.*

The growth in digital

gas lift W

HILE AFRICAN FIELDS are viewed by many as relatively new, the last few years have seen a growth in artificial lift technologies in the region – particularly offshore. This is also a theme being seen worldwide with according to the SPE (Society of Petroleum Engineers), over 95 per cent of the world’s oil wells produced with the help of some form of artificial lift. African examples include the deepwater Azurite field offshore the Republic of Congo, where multiphase pumps provide artificial lift for the field; the Ceiba field, Equatorial Guinea where multiphase boosting systems are in operation; and the Dalia field, Block 17, offshore Angola, which is being supported by gas lift technologies. There are a number of reasons for this. One is the need to increase oil & gas recovery, the other – perhaps more prominent driver, however – is the importance of generating cash flow from operations. Cash flow is diminished when a well is not continuously producing optimally or, more obviously, when it is shut in temporarily for intervention. In the longer term, such cash flow is also affected because the well cannot be produced effectively, has been lost due to intervention damage, or is subject to regular intervention & repair costs. While techniques such as ESP (Electrical Submersible Pumps) and multiphase boosting have tended to receive greatest attention, gas lift – the most common technique used offshore to lift reservoir fluids to the surface when wells are not able to sustain flow naturally – is starting to receive greater prominence as a means of supporting more financially viable wells. With gas lift, gas is injected into the production tubing to reduce the impact of the hydrostatic pressure where the reservoir pressures are not sufficient to force the hydrocarbons to the surface. Through a reduction of the density of the produced fluid column and a drawing down of the flowing bottom hole pressure that encourages reservoir liquids to enter the well bore at higher flow rates, gas liftenabled fields around the world can enjoy improved reservoir performance.

Digital gas lift – advantages and limitations There are also a number of benefits to gas lift as compared to other artificial lift techniques, such as ESP and rod pumps.

42 Oil Review Africa Issue Six 2012

These include the fact that gas lift can be applied in a wide variety of well conditions, can handle high temperatures, gassy, sandy and corrosive fluids and deviated wellbores; and can provide full through bore access to the reservoir for investigation, treatment and repair. Gas lift is also applicable to a wide range of production rates, being more suited to fluctuating well conditions than ESP and Rod pumps. Furthermore, the fact that in ESP installations, the fluid flow to the surface is through the ESP device means that ESP is particularly vulnerable to sand and other contaminants. With many African fields in remote areas with regularly changing conditions, the versatility of gas lift is a particular benefit. For all these advantages, however, there are limitations as well, particularly in regard to the information generated and the often crude forms of intervention required. Monitoring gas lifted wells, for example, is all too often limited to a very basic tick-box approach, focusing on wellhead pressure or the occasional fluid level or downhole pressure reading. Too often, operators have little information on pressure and temperatures at the point of gas injection, and little control or flexibility in being able to alter injection rates or depths as production variables change. In fast moving field conditions, as is often the case in Africa where field and well conditions can fluctuate dramatically, this is a significant disadvantage. In addition, the primary method of gas lift well completion still depends on the use of ‘side pocket mandrels’, where wireline interventions are used to change injection depth and make significant rate changes possible. This can be a long and cumbersome process, leading to the potential loss of the well (if the wire snaps and junk plugs the tubing, for example) or the halting of production as a new valve is installed in a side pocket mandrel. The side pocket mandrels also host either temperature sensitive ‘injection pressure operated’ devices or a simple orifice with fixed port size that are both prone to unstable operation when annulus and/or tubing pressures change. This often leads to unloading valves higher up the production tubing opening and injecting gas, potentially resulting in gas injection at the

With many African fields in remote areas with regularly changing conditions, the versatility of gas lift is a particular benefit. wrong point and valve failure as most unloading valves are not designed for continuous injection.

Making assumptions It is this lack of flexibility in gas lift operations which requires operators to depend on certain assumptions about the field conditions in which the gas lift will operate and which then subsequently determine the gas lift design. Operators have to make an assumption that

S11 ORA 6 2012 Technology_Layout 1 12/12/2012 16:44 Page 43

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S11 ORA 6 2012 Technology_Layout 1 12/12/2012 16:44 Page 44

the well will operate at a particular reservoir pressure, flow at a particular rate and with a specific water cut. Such assumptions, however, are not feasible as such conditions inevitably change, sometimes rapidly, over the life of a well. This lack of information, difficulties over intervention and reservoir assumptions can actually exacerbate well instability, leading to surges in liquid and gas flow that can shut down production separators, degrade field production uptime and affect casing and tubing integrity. What is clear is that while gas lift techniques come with significant benefits and potential, with African operators facing a wide range of conditions and fluctuating flow rates, the time has come to utilise the full benefits of gas lift but in a more intelligent way.

A new digital gas lift solution It’s against this backdrop that Camcon has spent the last few years developing and refining its new intelligent digital gas lift technology. The solution – known as Apollo – enables operators to vary injection rate and depth in real-time without production interruption and well intervention, and generate pressure and temperature information throughout the gas injection process. Central to the new technology is an extremely low energy pulse control which signals to switch an actuator between two stable positions to digitally operate a valve. The six electrically actuated valves, opened individually or in specific combinations, enables the real-time setting of injection rates. Apollo also eliminates the need for side pocket mandrels and wireline intervention, with settings tuned as well-bore conditions change through the life of the installation, giving down-hole control of gas-usage and preventing instability. The new digital solution also provides operators with continuous real-time information on pressure and temperature within the annulus and the production tubing at the point of gas injection. Having live information allows operators to optimise operating parameters and minimise gas usage without expensive and potentially risky slickline intervention. The result is improved production rates.

The route to market So what have the results been for Apollo in the field? At present, it’s too early to say. Apollo is currently being deployed in an onshore well in Oman. In this case the deployment was part of a normal work over programme for a high productivity well with the intelligent gas lift method used to improve the well’s production performance. We hope to be able to unveil the results in the coming months. A recent simulation modelling analysis, conducted by Laing Engineering & Training

44 Oil Review Africa Issue Six 2012

PI bpd/psi

Conventional Design Single Orifice @ 4190 Orifice @ 6770 ft ft Oil bopd

Gas lift mmscfd

Oil bopd

Gas lift mmscfd

APOLLO Oil bopd

Gas lift mmscfd

Depth of Injection

2,865

2.0

2,360

2.0

3,125

2.0

10,555

4,625

2.0

4,060

2.0

4,650

2.0

6,970

5,895

2.0

5,330

2.0

5,920

2.0

6,970

Figure 1 - Life Cycle Stage: Early Life – 3 Months

PI bpd/psi

Conventional Design Single Orifice @ 4190 Orifice @ 6770 ft ft

APOLLO

Oil bopd

Gas lift mmscfd

Oil bopd

Gas lift mmscfd

Oil bopd

Gas lift mmscfd

Depth of Injection

2,165

2.0

1,550

2.0

3,005

3.0

15,615

3,455

2.0

2,715

2.0

4,245

3.0

10,555

4,360

2.0

3,575

2.0

5,240

3.0

10,555

Figure 2 - Life Cycle Stage: Mid Life – Water Injection Support/Higher CHP (Casing Head Pressure)

Services (LETS), however, illustrates the benefits of the new technology with impressive results in regard to the delivery of improved production rates at different stages of the reservoir lifecycle. The analysis compared the performance of a standard, multi-mandrel gas lift design against Apollo to identify the maximum practically achievable production rates alongside the maximum practically achievable gas injection rates. LETS developed an example subsea well in moderate water depths, drilled to a total depth of 17,600 ft MD (Measured Depth) and with a 4.5” by 5.5” production tubing string inside a 7” liner and 9-5/8” production casing – parameters which might be expected in some offshore African fields. The oil was a light 38’ API fluid with a reservoir temperature of 127°C. The key variables examined were the well productivity index, reservoir pressure and water cut. As is often the case in real-life reservoir situations, we anticipated that each of these parameters would change over the lifetime of the well. The analysis found that the two scenarios deriving most benefit from gas lift are at the early life stage after three months and the midlife stage with water injection support. Figure 1, for example, shows the bopd (barrels of oil per day) comparisons at the three month life cycle stage for three potential PI values with the new digital gas lift technology already showing increased bopd. The mid-life stage is also particularly important as reservoir pressure has fallen to an extent that it cannot support natural production. Here, Figure 2 shows improved bopd with the new technology, which can also set higher injection rates at 3.0 mmscfd. The ability to open and close the Apollo units at will, and to vary the equivalent port size meant that even greater production

increments could be delivered in the scenarios where additional casing pressure or additional gas lift gas became available. For example, a gas injection rate of 3.0 mmscfd was modelled for the ‘mid life’ life cycle stage as illustrated in figure 2 with a higher casing head pressure as well. As one can see, Apollo continued to deliver greater incremental production. The results found that the new technology can deliver as much as 1,000 bopd more oil production from a typical well compared to traditional gas lift equipment and in one scenario represented up to 110 per cent more production.

The time has come to utilise the full benefits of gas lift but in a more intelligent way. What next? So what comes next? Once we have field test results to point to, we hope to ramp up quickly with African operations – both onshore and offshore – a key target. We have already put in place an extensive distribution network, for example – particularly in the Middle East – and have teamed up with Ultra CEMS, a leading contract electronics manufacturer of high reliability products, to manufacture the new product. At a time when sustainable cash flow and increased production from producing wells has never been more important, we are confident that pollo is coming to the market at exactly the right time. Watch this space! ■

*By Ian Anderson, Camcon Oil

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East Africa

South Tanzania invests in the people of Tanzania SOUTHEY TANZANIA, A division of Southey Contracting Offshore Division and a Tanzanian-registered company, has a philosophy of investing in the countries in which it operates and has therefore been established to not only provide services to the companies involved in the development of the resources sectors in Tanzania, but to also develop the skills of the local personnel. Southey Tanzania provides specialist access, inspection and maintenance services to the oil, gas and mining sectors of East Africa. The services provided include corrosion protection, UHP water jet blasting, abrasive blasting, tank cleaning, scaffolding, thermal metal spraying, non-destructive testing, material inspection services, lifting gear certification, maintenance and engineering solutions, unique access solutions and marine crew assignments. Country Manager, Rudi Schellhorn stated: “We add value to our clients through our engineering capabilities in the various business sectors in which we operate. Importantly, we train local employees to our exacting standards, thereby offering our clients skilled operators and artisans to meet legislated local content requirements”. The skills developed are based on the projects to which Southey Tanzania is exposed to by their international clients. Southey has been fortunate in securing varied on- and offshore projects over the last few years that have ensured ongoing growth and development of their personnel. In the past year, a strong partnership has been developed with VETA in Mtwara and the training that has been offered to date includes a scaffold erection programme; a scaffold inspector programme; and life skills training for Tanzanian trainees currently on a Petrobras Tanzania initiative. The top five students on the Petrobras training programme at VETA will be sent to South Africa during 2013 for offshore survival training, with the aim of placing these new recruits on existing projects that Southey has offshore Tanzania. Other courses that Southey has offered to its Tanzanian personnel in Cape Town and in-country include: English proficiency programmes; maritime short-course studies; offshore survival certification; local tax understanding; and leadership programmes. Training and development costs for the past year have exceeded US$160,000 and that is before the selection of the five new candidates for 2013 training,” concluded Schellhorn. “Our Tanzanian Southey’s mobile multi-disciplined teams specialise in effectively mobilising equipment and manpower to any of their operating areas swiftly in Ghana, Gabon, Angola, Republic of Congo, Mozambique and Tanzania, all fully supported by an administrative and logistics hub in Cape Town.“

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Technology

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In an unforgiving environment where every day of unscheduled downtime can result in major financial losses, it is vital that oil and gas companies maintain their equipment by taking advantage of the various advanced lubricants at their disposal,, writes Akram Reda, Industrial Marketing, Europe, Africa & Middle East, ExxonMobil Lubricants and Specialities.

Utilising lubricants to

reduce downtime M

AJOR OIL AND gas producers face a daily challenge to meet current production targets, placing a great responsibility on oil and gas companies operating in the region to maximise productivity and reduce unscheduled downtime. Across the entire production process, from drilling to delivery, advanced industrial lubrication can play a key role in keeping operations running efficiently, 24 hours a day, as well as reducing operating costs. Drilling and exploration is a significant investment for oil and gas companies, with rig hire alone costing as much as tens or even hundreds of thousands of dollars per day. Taking this into account, companies must avoid any unplanned downtime. A typical offshore oil and gas rig is reliant on a number of lubricants to ensure its efficient operation. Turbines and reciprocating engines provide primary and auxiliary power, gears and bearings are crucial in draw works, cranes, mud circulating, top drive and rotary tables and compressors’ power refrigeration and air systems. Whether it is an engine oil, turbine oil, gear lubricant, hydraulic fluid or grease, one equipment failure can bring the entire operation to a halt. At the processing stage, lubrication remains critical to the overall productivity and performance of a plant. Take for example the key role of a turbine oil in keeping operations online. A turbine failure in an oil refinery and resulting shutdown can cost millions of dollars. When it comes to transportation, marine vessels depend on a range of lubricants to ensure they remain fully operational. From the main engine, propulsion systems, auxiliary engines and thrusters to the deck crane, deck machinery and winches, a wide range of lubricants are required to ensure oil and gas is efficiently transported around the world.

Advanced lubrication Advancements in lubricant technology, especially fully-synthetic based products, have resulted in significant breakthroughs regarding the extension of equipment life and oil drain intervals. These breakthroughs can help oil and gas companies maximise productivity and reduce unscheduled downtime throughout the drilling, processing and transportation chain. For example, Mobil SHC fully synthetic lubricants can last up to six times longer, with upper operating temperature limits that can typically reach 50°C (90°F) higher than mineral oils. The high temperature performance of lubricants is particularly important for oil and gas companies operating in the Middle East, where the high ambient temperature coupled with the high speeds and heavyloads placed on applications, requires a lubricant which can maintain protection in high-operating temperatures. Other research and development areas that leading lubricant providers have focused on in recent times include improving the energy efficiency of equipment while maintaining these extended operating periods. Recent breakthroughs from Mobil Industrial Lubricants include lubricants to improve the energy efficiency of natural gas engines that are used to power drilling and production rigs. These are in addition to hydraulic, gear and bearing oils which are used in a variety of applications. The natural gas engine oil, Mobil SHC Pegasus, uses breakthrough technologies to optimise equipment productivity and protection and is the first gas engine oil formulation on the market to deliver real energy saving potential. Extensive independent university laboratory and field tests have demonstrated that the product helps reduce fuel consumption by up to 1.5 per cent*. The new Mobil SHC Pegasus formulation also delivers the potential for increased oil

46 Oil Review Africa Issue Six 2012

At the processing stage, lubrication remains critical to the overall productivity and performance of a plant.

Beyond oil analysis, visual system inspections should be conducted regularly to check and document the condition of systems. drain intervals of more than 16,000 hours - three to four times that of premium natural gas engine oils. This can help reduce unplanned downtime as well as reduce the amount of waste oil generated. ExxonMobil’s state-of-the-art hydraulic oil, Mobil DTE 10 Excel, has been proven to help industrial organisations increase productivity, reduce unscheduled downtime and improve the energy efficiency of their machinery. Compared to standard hydraulic oils, Mobil DTE 10 Excel can provide up to a six per cent improvement in hydraulic system efficiency** and 300 per cent increase in oil drain intervals. The latest addition to the Mobil SHC brand of high-performance synthetic lubricants, Mobil SHC 600 Series oils, are expertly formulated to deliver a number of performance advantages over conventional oils. Featuring the latest Mobil SHC technology with advanced synthetic base fluids and a proprietary additive system, the oils can deliver a service life up to six times longer than competitive mineral oil based gear and bearing lubricants. In addition, developed through extensive laboratory and in-service testing with some of the world’s leading equipment manufacturers, the next-generation Mobil SHC 600 Series oils exhibit energy savings of up to 3.6 per cent*** compared with conventional oils.

Maximising productivity In order to help maximise the productivity of machinery and reduce costs, ExxonMobil recommends incorporating an oil and equipment condition monitoring programme alongside the use of high quality lubricants. As part of routine maintenance, the "health" of the lubricant and the equipment itself should be regularly checked. Typically, it is advised that maintenance professionals perform quarterly oil analysis and annual system inspections.

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Technology

Examining changes in the oil analysis data over time (trending) is necessary to assess the condition of the lubricant. By trending oil analysis data it is possible to proactively address undesirable conditions before they become problems, which is crucial given the huge potential downtime costs associated with an offshore rig being offline for any period of time. For equipment maintenance professionals who want an effective oil analysis monitoring programme, there is ExxonMobil’s proprietary online Signum oil analysis programme. Signum oil analysis offers engineers immediate access and direct control of their lubricant sampling programme. Beyond oil analysis, visual system inspections should be conducted regularly to check and document the condition of systems. Inspection data can be used to establish the optimum time to perform maintenance on critical components such as filters, valves, hoses and pumps. Comprehensive leak detection should also be performed, especially if excessive oil usage is noted during a routine system inspection.

On the ground support Due to the 24/7 nature of the oil and gas sector, it is important that companies have access to experts that can work alongside in-house engineers to develop optimised lubrication solutions for applications. Variables such as operating temperature, load, cycle and age of equipment have an impact on the most appropriate lubrication, monitoring and maintenance package. To service oil and gas companies in the Middle East, ExxonMobil has a Field Engineering Services (FES) team on the ground to offer technical support to companies operating in the region. On a day-to-day basis they work with companies to address lubrication issues as well as proactively identifying ways in which productivity can be further increased by switching to more advanced lubricants. The technical specialists in the Middle East are part of a global FES team, which shares application expertise and best practice through its work in

By trending oil analysis data it is possible to proactively address undesirable conditions before they become problems.

supporting oil and gas companies in other areas of the world such as the Gulf of Mexico, the North Sea, Russia, the Asia Pacific region and Africa. To augment this technical expertise, ExxonMobil has specialist strategic distributors located in all of the key Middle East oil and gas markets to offer fast and reliable delivery of Mobil Industrial Lubricants. Oil and gas companies looking to optimise the productivity of their equipment need to ensure they have access to the latest lubricants and services, as well as application expertise. ■

If you can imagine it, we’ll help you lubricate it.

There’s one thing you should know right away: When you choose a base oil from Nynas, you’re choosing a naphthenic product. What are the beneﬁts? Excellent low temperature properties and high solvating power. The latter is provided by the naphthenic molecules in our oils. Polycyclic aromatic compounds are kept to a minimum as most of them are converted by our hydrotreatment technology into harmless molecules – all without compromising the oil’s solvating power. When you then add a wide range of base oils and the ability to customize blends to your requirements, it’s easy to see why we can help you lubricate just about anything. For more, visit www.nynas.com

Nynas South Africa (Pty) Ltd T: +27 10 590 1052 / +27 82 496 2730 E: alistair.meyer@nynas.com www.nynas.com

Oil Review Africa Issue Six 2012 47

Technology

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Red Spider’s eRED-FB successfully completes operation in West Africa RED SPIDER, THE Remote Open Close Technology (ROCT) specialist delivering major savings and reduced risk to the oil and gas industry, has successfully completed an operation worth over US$484,000 with a major energy company using its eRED-FB technology off the coast of Equatorial Guinea. Red Spider invested almost US$3mn over two years into the research and development of new technologies including the eREDFB. This was the product’s first run within the region. eRED-FB provides a downhole barrier that can be opened and closed by remote command, removing the need to set a plug via conventional intervention methods. In this application eRED-FB successfully eliminated deep set interventions during the completion placement phase of the subsea horizontal well. Deployed as an integral part of the tubing string, eRED-FB was run in hole in the open position to a depth of 2,774 m at a deviation greater than 80°. During the operation it was remotely operated twice using pre-programmed pressure and time commands, firstly closing the tool to provide a means to set the packer and test the tubing integrity, then opened with maximum flow area maintained for production. This provided time and money saving to the client whilst eliminating all the risks typically associated with the intervention of a highly deviated well. Red Spider Chief Executive Steve Nicol said: “Everyone at Red Spider is thrilled the eRED-FB operation was such a success. We look forward to further utilising the tool globally and expanding our services within the West Africa region. “The first product in Red Spider’s ROCT range was eRED, a computer

Tenaris demonstrates dopeless technology TENARIS RECENTLY PRESENTED its dopeless technology – dry, multi-functional coating – at the Baker Hughes facilities in Takoradi. The trial featured two 5 1/2-in. 20# NK-95 13Cr pup joints with TenarisHydril Blue Dopeless connections and two 9 5/8-in. 47# L80 pup joints with the same premium connection technology. During the event, the connections in casing and tubing sizes were assembled and disassembled up to eight times, proving the technology’s consistent performance to withstand multiple make-and-breaks with enhanced galling resistance and frictional consistency. Attendees observed how the coating withstands these operations without the need to apply thread compounds. “The more dope you use, the more contamination you bring to the well and the environment. With dopeless technology, all dope-associated hazard is eliminated,” said Daniel Martey, senior petroleum engineer from Ghana National Petroleum Corp. “It would be better if everybody switched to connections with Dopeless technology. I am going to advise my drilling manager,” said Mubarak Ismaeel, drilling engineer from Hess Corp. During a second stage, the connections were exposed to drilling mud contamination, without degradation of the dopeless coating. Amaja Oilfield Ltd., Tenaris’s partner in the country since 2010, assisted with the activities at their Training Center and helped with Dopeless® Technology benefits demonstrated to customers in Ghana. logistics.

48 Oil Review Africa Issue Six 2012

controlled ball valve technology that can be repeatedly opened and closed by remote command, which has completed over 120 runs and is rapidly becoming the valve of choice for intervention type work. The eRED-FB full-bore valve has now proved that the eRED technology can be scaled-up and we are confident that it will emulate the eRED’s success during completion placement operations.” The eRED-FB is expected to deliver savings of between 32 to 38 hours (US$650,000- $800,000) by eliminating the requirement for any wireline runs during a completion placement operation. Eliminating the requirement to deploy traditional wireline equipment speeds up the completion process, bringing wells on stream sooner and reducing the risk of exposure to bad weather. This also removes the need to rig-up and rig-down wireline and PCE equipment, which reduces the risk to personnel, equipment and the operation. Red Spider has alsowon a three-year contract to supply downhole devices on Total’s Anguille field offshore Gabon. As part of the three-year agreement, Red Spider will supply and service eREDs for the field. The company will deploy 12 of its 3.25-in. remotely operated eREDs, two in each of the six wells. These will be positioned as barriers within injector wells, with one eRED used as a shallow-set barrier and the second as a deep-set barrier. The technology allows opening and closing of the valve numerous times, which according to Red Spider, potentially saves many additional hours of rig time. Use of the eREDs in tandem should also generate financial savings, decreasing necessary wireline runs tenfold during each operation.

Caterpillar gas generators reduce operational costs MANTRAC NIGERIA LTD, sole dealer of Caterpillar Inc in Nigeria, said the newlyintroduced gas generators would reduce the cost of running business in Nigeria. Mantrac Managing Director, Edmund Martin-Lawson, said recently during a seminar, entitled, ‘Gas to Power’ that the innovation would facilitate business operations. Martin-Lawson said gas was cheaper than diesel and that Mantrac was working to put across solution to its clients. He said, “Today, you know that the public power situation in Nigeria is not the best. Everybody is using diesel which is expensive to power their generators. “Fortunately, the Nigerian government has gas. Gas is cheaper than diesel. Caterpillar has introduced gas generators to help our customers reduce the cost of running their business.” He said the gas industry in Nigeria had been growing year by year, noting that the product would add further impetus to its growth potential. “The implication of the product

we are bringing into the market is to try and grow it faster by reducing the cost of the products to the end users. By so doing, the cost of doing business will reduce because it saves money,” Martin-Lawson said. Martin-Lawson said CAT gas generators could convert clean local fuel source efficient into electricity. He said, “It will deliver power close to population centres, reducing line losses and increasing grid security. It will also provide longer maintenance intervals and reduce oil consumption for lower service costs.” He said with the gas-powered generators, emission from gas generators was lower and better for the environment.

S12 ORA 6 2012 Innovations_Layout 1 12/12/2012 16:48 Page 49

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ICT

The last few months have seen significant exploration activity in East Africa as long-awaited deals are signed, drilling activity increases, and more and more E&P companies fast-track their exploration activities.

Reducing exploration timelines and supporting

seismic with FTG The sheer vastness of the remote exploration acreage presents significant challenges.

HE DISCOVERIES IN Uganda in the Albertine basin have instigated significant exploration enthusiasm in this vast region, as have the licensing of vast tracts of land (and lakes) in Ethiopia, Kenya and Malawi. Tullow has reported encouraging results from their first well in Kenya’s Block 10BB, demonstrating a working petroleum system in the region. It is discoveries, such as this, that have boosted the Kenya's oil reserves estimate by one third to around four billion barrels, the largest in East Africa. Furthermore, in addition to the independent operators, many of the majors and NOCs are looking to get a slice of the action. France's Total and China's CNOOC recently paid US$2.9bn to buy interests in Tullow's blocks in Uganda which will usher in as much as US$10bn of investment into the region. Italy's Eni is also among the latest companies to enter Kenya with the purchase of three blocks and US companies are also showing interest with Marathon Oil Corp recently paying US$35mn to Africa Oil Corp for stakes in two Kenyan prospects and Anadarko Petroleum Corp finding gas offshore Mozambique and also acquiring rights to explore off Kenya’s coast.

The key challenges - size and geology Despite the rush of recent activity, however, the exploration challenges in such frontier regions remain significant. Firstly, there is the sheer vastness of the remote exploration acreage with an average block size between 15,000 and 20,000 sq km. Many of these areas are also characterised by poor seismic response or relatively old (and often low fold) 2D seismic, leading to the very real risk of non-productive exploration surveys and dry wells or basins of considerable significance being missed.

50 Oil Review Africa Issue Six 2012

While such exploration disappointments might be relatively easy for the larger international operators to absorb, for small to medium-sized independents who are conducting much of the onshore exploration in East Africa to date, this comes with significant risks. In addition, there are the ever challenging timelines and investor pressures to get to first oil as quickly as possible. The host Governments are also adding to the time pressure to explore. The Kenyan government announced recently that they want exploration companies to speed up their work programmes with subtle warnings that they may invoke their right to cash in guarantees if companies fail to do so. The geology can be a challenge as well. The East African Rift, which extends from the Red Sea/Gulf of Aden through Sudan, Uganda, Ethiopia, Kenya, Tanzania and Mozambique, is one of the world’s truly unique geologies that consists of rift margins, varied depositional settings, and a raft of Paleocene, Oligocene, and Miocene sedimentary rocks (clastics) with varying levels of maturity. Basalts and other volcanic extrusives also render conventional seismic reflection techniques difficult to interpret. While the Tertiary rift might be relatively simple, the Cretaceous rifts in countries such as Kenya and Mali come with their own geological challenges as well. It’s perhaps no surprise therefore that less than 200 wells have been drilled to date in a huge area of 2.3mn sq km within the East Africa Rift, highlighting the potential for future exploration.

Today, FTG is being included as part of the work commitment for bid preparations and also as a crucial element of the geophysical commitment.

So what are the techniques of choice in tackling the exploration challenges of East Africa?

The growth of Full Tensor Gravity Gradiometry (FTG) While 2D and 3D seismic technologies and their associated acquisition and processing methods are continuing to provide crucial data to better understand the East African subsurface, another technology – Full Tensor Gravity Gradiometry (FTG) – is now proving to be an invaluable addition to existing seismic data, providing high resolution constraint to the seismically derived geological models. Today, FTG is being included as part of the work commitment for bid preparations and also as a crucial element of the geophysical commitment. FTG maps the small density variations in underlying rocks by measuring the gradient of the earth’s gravity field. FTG provides an increased signal-to-noise ratio and wider bandwidth than conventional gravity measurements and, because it measures the full tensor of the gravity signal, it is able to map offline effects of the underlying geology. FTG is playing a key role in East African exploration today – firstly, through the simple and cost effective means in which the data is acquired and, secondly, through the quality of the data that provides a crucial complement to the seismic, supporting the design and targeting of such surveys. Being an airborne technique, FTG can explore vast geographic areas of East Africa accurately and efficiently with the non-invasive nature of the technology ensuring that there are no environmental or cultural implications to the data acquisition. The speed and ease in which the data can be acquired is of particular value to smaller independents who have limited exploration budgets as well as companies wishing to indentify the optimal location of seismic lines or wishing to add

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critical constraint to their seismic interpretation. The challenges of positioning seismic in say a 10,000 or 15,000 sq km block is fraught with difficulties. Poorly located lines may not image the geology optimally and potentially condemn a vast area as being non-prospective - sometimes missing basins and sub basins along the way. Without successful illumination, portions of the seismic volume will always have poor resolution, even with the most accurate velocity model.

It is the quality of the data generated that is adding such value to East African exploration. In addition to the easy and cost effective acquisition, it is however the quality of the data generated that is adding such value to East African exploration. FTG measures the variations of the Earth’s gravity field with such a high degree of resolution and bandwidth that detailed basement structure maps can be derived which, in turn, allow for the optimal positioning of the seismic. The East African Rift is an ideal geological setting for FTG. The relatively young sediments juxtaposed against a (much denser) Achaean basement, is ideally suited to being mapped with FTG. Other advantages of deploying FTG in the unique exploration setting of East Africa include an improved definition of the sedimentary basin and internal architecture and the identification of structural leads, which can become a focus for seismic acquisition. The early seismic in the basin can also be calibrated to the FTG data and, if necessary, the seismic programme can be altered in places of shallow basement or insufficient depth of burial of potential source rocks. FTG also brings offline components into the

An ArKex FTG airborne platform.

datasets helping establish the influences on 2D seismic data outside the plane of acquisition – highly beneficial to operators in determining how two independently interpreted faults may or may not be connected. By measuring all nine components in all three directions of the gravity field, FTG allows the interpreter to develop structural models and conduct velocity analysis outside the plane of 2D seismic acquisition, further complementing the seismic data.

A roadmap to seismic The importance of FTG’s role in supporting seismic cannot be overstated. With the cost of a seismic line as much as US$20,000 and with a lack of understanding as to what the geology is doing, exploration costs can often spiral without the use of FTG. It is simply not possible to cover 15,000 sq km blocks appropriately with 2D lines. When looked at it from this perspective, investing in FTG can deliver almost immediate returns on investment with FTG optimising the design and acquisition of the seismic surveys, optimising the earth models, addressing illumination problems, and reducing risks and costs in East African exploration. And as well as the accuracy of the surveys, there is also the speed to first oil. I recently spoke to an operator who was awarded a Block

in 2010 and delivered first oil in 2012 – a two year turnaround which no one could have dreamed of previously. So what FTG surveys are taking place in East Africa to date? There’s no doubt that FTG is seeing considerable ‘market buoyancy’ in the region. Operators such as Tullow and Africa Oil have already acquired large FTG surveys over their Kenyan and southern Ethiopian holdings to assist their exploration activities. The much publicised Ngamia-1 well in Kenya’s Block 10BB was drilled on the back of an FTG survey and a focused seismic campaign put into place within two years of the Block’s award. In addition, many recently signed production sharing contracts have FTG surveys in their work programmes. Ignore it at your peril! FTG is today a powerful de-risking tool in East African exploration – a crucial pre and post-seismic application that can help operators direct their future exploration towards the most potentially prospective areas. The acquisition of broadband, high resolution gravity data throughout the exploration cycle is having a significant impact on exploration workflows. E&P operators in East Africa that bypass FTG do so at their peril! ■

Paul Versnel, ARKeX

Schlumberger launches new wireline formation testing service SCHLUMBERGER HAS INTRODUCED the Saturn* 3D radial probe as the newest module for the MDT* modular formation dynamics tester. With the Saturn probe, customers can now obtain pressure measurements and fluid samples where they were not previously possible due to reservoir conditions. “Customers expect Schlumberger to be able to fully characterise reservoir fluids in today’s complex reservoir environments,” said Catherine MacGregor, president, Schlumberger Wireline. “Whether the reservoir is unconsolidated, has low permeability or contains heavy oil, we can now perform pressure measurements and downhole fluid analysis and bring high-quality samples to surface.” The Saturn probe is comprised of four elliptical suction probes mounted at 90° intervals circumferentially around the tool, providing the largest surface flow area of any probe in the industry — more than 500 times that of a standard probe. Analysing reservoirs from more than 85 tool settings, the Saturn probe has been run in South America, Africa and the Middle East in environments ranging from onshore to deepwater. In Mexico, the Saturn probe successfully sampled fluids as low as 7 API gravity from unconsolidated formations with unconfined compressive strength as low as 300 psi, which would have been difficult using conventional probes. In the Middle East, the Saturn probe sampled fluid in formations with mobility less than 2 mD/cP, enabling the customer to accurately identify the location of the hydrocarbonwater contact point.

52 Oil Review Africa Issue Six 2012

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Satellite Communications

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Satellite communications services are changing — slowly. The growth of the Ka band option and a new approach to existing services should eventually have a major impact on costs and competition. Could oil and gas companies benefit? Simon Bull of COMSYS* thinks they could and, in the first of two interviews on the subject, tells Vaughan O’Grady why.

Could competition cut

communications costs? T

ECHNOLOGICAL ADVANCES IN the oil and gas industry often take a long time to have an identifiable impact. Breakthroughs may be announced but the route from announcement to implementation is never an easy one for an industry of such size and complexity. By contrast, telecommunications has, in little more than 20 years, produced numerous breakthroughs that have very quickly changed our lives and work practices: mobile cellular, 3G, 4G, WiMax, Wi-Fi and fibre optics among them. Fibre optics in particular has a very specific application to oil and gas, with companies buying or building networks, often offshore, to guarantee reliable communications and high data rates. When this isn’t possible — in deep, ultra-deep or very isolated locations — or when some sort of fall-back option is desirable, satellites come into play. Satellite communication, however, seems to be one of the parts of the telecommunications industry where, like oil and gas, a giant leap forward can take time to reach the market. That isn’t too surprising; building and launching even one satellite is a slow process. But even before that happens a satellite company has to choose the band in which it will transmit: L, C, Ku and, increasingly, Ka, or a combination of them. As we noted in issue six of ORA in 2011, as you move up the main satellite frequency bands (from L to C, Ku and Ka) you gain in concentrated power but lose in terms of coverage. Until recently this meant Ku and C slots were very popular — so popular in fact that space on these bands can be hard to come by. The company then has to build enough satellites to cover the globe, or at least the parts where business is likely be most reliable; in the case of oil companies that business is communications via handheld devices and VSATs. But the service doesn’t sell itself so a sales force needs to find partners and paying customers. There’s also the question of who the company will partner on the ground to manage all this: Hermes, Harris CapRock or RigNet, for instance, are companies that provide managed communications down on the ground or at sea. And once the satellites are in place they can’t, unlike, say, copper cable, be easily replaced or upgraded. This means that a launch is not likely to be rushed.

54 Oil Review Africa Issue Six 2012

So when Simon Bull, senior consultant with specialised telecommunications consultancy COMSYS*, speaks of an important breakthrough in satellite communications that could benefit oil and gas, that breakthrough could be some years away from real-world implementation. Nevertheless, this story is an intriguing one. It involves Intelsat, a major provider of satellite services. Intelsat recently announced Epic, which is, to quote Intelsat’s press material, “a high performance, next generation satellite platform that delivers global high-throughput technology without sacrificing user control of service elements and hardware”. In more comprehensible language, end users, including oil and gas companies, can access higher throughput in bands — Ku and C — that they are already using with no major changes required to their hardware. If true, this turns a number of assumptions on their head.

Ka-band satellite services will boost broadband access across Africa.

But let’s step back and put this in context. As we have already indicated, fast, radical change is unusual in the satellite industry. Building, launching and operating a satellite historically can cost from $250m — $400m by Bull’s estimate and bandwidth availability is often slow in coming. Or at least it was. Today the reliability problems relating to weather interference in the otherwise highly desirable Ka band have largely been overcome and satellite services providers are adopting it in every greater numbers, led by global mobile satcoms provider Inmarsat. The greater power of Ka also means greater throughput — “in theory,” says Bull, “twice as much bandwidth for the same price”. However, coverage was, at first, a problem. A spot beam

covering Europe would include areas of no demand so cost per bit didn’t necessarily fall. Again, however, this problem has been solved, thanks to smaller spot beams, targeted coverage, higher bandwidth and new efficiencies like frequency reuse. Inmarsat is on the verge of offering the first dedicated global Ka band service. And more Ka band services will follow because many more frequency assignments are available in Ka than in Ku and C where, as we have noted, just getting a new slot could take years.

Is Ka good new for oil and gas? Possibly. Ka band services may appeal in some of the oil and gas areas covered by ORA and ORME: much of the Middle East and North or East Africa where the heavy rainfall that can cause attenuation problems for Ka band services is hardly the norm. There is even a Ka band service planned for West Africa. Yahsat, the UAE-based satellite operator, recently launched the region’s first Ka-band IP trunking service, and Bull says, “Yahsat now has Ka band coverage of Nigeria and Angola so it is going to happen [there].” However, he points out that there is so far no clear indication of the actual operational experience of Ka band in those regions. Inmarsat is therefore offering L Band backup in case Ka goes down, which may happen: Inmarsat is a global service after all and may need to cover areas unfriendly to Ka. However, L band is not necessarily able to cope with high throughput, so would not be acceptable too often or for too long.

Fast, radical change is unusual in the satellite industry. In any case the reality is that to use Ka even oil and gas companies in Saudi Arabia and Egypt and their managed communications partners will probably need new equipment given that they may have used other bands until recently. Meanwhile much of the West African coast operators (and operators in other heavy rainfall areas like offshore Brazil) still need the reliability of Ku and C.

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services and offer new ones using Epic. Intelsat’s business model clearly appeals to that company — and not just to Harris CapRock. MTN has signed for the cruise business and Panasonic for airlines.

Even more satellite competition is on the way and the fibre option could further move the initiative towards the customer. But that service is still a few years off. So how should oil and gas companies react? “I think for the oil and gas community there’s a lot of good news in this,” says Bull. “Firstly they should be rubbing their hands and saying: “Great! Competition!” Secondly it looks like options are coming along that will give them exactly what they want – more bandwidth at a lower price – but in the conventional bands that they’re already using – Ku and C.” Another point involves the service providers. A key component of the Inmarsat scheme is that it takes managed

communications companies like Hermes, Harris CapRock or RigNet out of the equation. Inmarsat is taking all of this in-house, which may guarantee the service provider reliability oil and gas companies worry about. However, says Bull, “Oil and gas guys may complain but they actually value their service providers quite highly. They do see the value of having a company there, an operator, that supports them across a wide variety of things, can provide the technicians, the helpline, the support and the integration that they need. From that perspective that’s the other plus point: [Epic] keeps the existing structure in place that they know.” But that’s not the only potential good news for oil and gas communications: even more satellite competition is on the way and the fibre option could further move the initiative towards the customer, as we shall see in part two of this discussion. ■

**COMSYS is a specialised telecommunications consultancy company with a core expertise in satellite and VSAT systems. The Comsys Maritime VSAT Report 3rd Edition has recently been published. It includes coverage of the oil ands gas sector. For more information go to www.COMSYS.co.uk

Oil Review Africa Issue Six 2012 55

Satellite Communications

Which brings us back to the Intelsat announcement. This, says Bull, was one of the big talking points at the recent Comsys VSAT conference in London in September. He explains: “Out of the blue, Intelsat has come up with a completely new concept. [It has] a high throughput satellite but has got a matrix on board the satellite which allows it to go up and down in any beam [with] any carrier.” Thus, if you’re a provider of managed communications at ground or sea level, provided you’re within the footprint of that satellite you can use your existing equipment; you don’t have to throw away your US$50mn or US$100mn worth of infrastructure investment. This is because Epic will, in theory, offer more bandwidth at a lower price and a higher power, enabling smaller antennas on the ground — and do so in the Ku and C bands. It already has the Ku and C band frequency assignments, true, but it seems to have found a way to make them go a lot further. But can Intelsat really offer this? Well, the launch plans were only announced in early summer and in-service dates for the first two Epic satellites are not until 2015 and 2016, but oil and gas companies have surely already noted that a specialist in their area, Harris CapRock, is signed up to expand existing

ICT

S14 ORA 6 2012 ICT 02_Layout 1 12/12/2012 16:59 Page 56

African Petroleum selects Paradigm

Voice & data satellite services for North Africa

AFRICAN PETROLEUM HAS selected the Paradigm interpretation suite on Microsoft Windows as its corporate standard for seismic interpretation. The company additionally announced that its interpretation applications have subsequently played a significant role in African Petroleum’s oil discovery offshore Liberia. “African Petroleum has successfully used Paradigm’s advanced seismic interpretation tools for detailed stratigraphic interpretation of multiple fan systems in blocks 8 and 9 offshore Liberia, resulting in a significant oil discovery,” said Adrian Robinson, exploration director at African Petroleum. “SeisEarth and VoxelGeo allowed us to rapidly interrogate multiple, large 3D seismic and attribute volumes to predict reservoir and seal facies as well as potential aerial net-to-gross variation. Visualisation of our data in a collaborative environment helped bring the team together to select the best well location.” African Petroleum selected the Paradigm interpretation suite based on its ability to easily work at the regional project scale with large seismic volumes and large numbers of seismic attributes.

GLOBALSTAR EUROPE SATELLITE Services Ltd, a wholly owned subsidiary of Globalstar Inc and a leading provider of mobile satellite voice and data services to businesses, governments and consumers, has signed an authorised distribution agreement with Virtual Mobile Data (VMD). VMD will act as a National Distributor for Globalstar's suite of duplex and SPOT products to the defence, government, maritime, oil and gas, transportation, tourism and mining sectors within the Tunisian and Algerian Mainland Territories via their established dealer channel. "We are delighted to be working with VMD within the expansive, fast developing markets of North Africa. They are uniquely positioned to offer our suite of Duplex and SPOT products to the Government, B2B and B2C markets within that region” said Mark O’Connell, Director European Sales & Business Operations, Globalstar Europe Satellite Services. In September, Globalstar eliminated roaming charges between Independent Gateway Operator, Globalstar Avrasya of Turkey and Globalstar Europe. Globalstar Europe Satellite Services gateway in Aussaguel, France and Globalstar Avrasya’s gateway located in Ankara, Turkey are now provisioned to facilitate flat rate telecommunications throughout all of the European subcontinent as well as Northern Africa, the Middle East, most of the Mediterranean and the eastern Atlantic Ocean maritime region. Globalstar is currently planning to launch six additional LEO (low-earth orbit) satellites in early February 2013, completing its second-generation satellite launches. The Globalstar second-generation satellite constellation is designed to support the company's current line-up of voice, Duplex and Simplex M2M data products and services including its suite of SPOT retail consumer products. The new satellites are designed to last for 15 years, twice the lifespan of Globalstar's first-generation satellites.

Hermes Datacomms offers wireless mobile VSAT HERMES DATACOMMS, A company that provides communications to the oil and gas industry particularly in difficult and challenging locations, has developed a mobile wireless VSAT solution. The trailer mounted system is selfcontained, simple and reliable in hot, dusty and wet conditions. With the touch of a single button, the system is deployed and ready to use in four minutes, providing instant WiFi Internet access. Bill Green, Global Account Director, expanded, “We are very excited about this new product development. It builds on our existing deployed mobile returns in Ethiopia and Kenya, offering an even greater level of simplicity and reliability”. Barry Bouwmeester, Account Manager, explained,” Hermes Datacomms now provides extensive coverage in Africa using AMOS5 satellite which features a high power C-band beam and regional KU-band beams. The new Wireless mobile VSAT technology is an add on to the services we can offer to our customers who are often working in difficult and challenging environments”.

56 Oil Review Africa Issue Six 2012

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ASCO Group invests in Advanced Logistics THE ASCO GROUP, a leading international oil and gas services company, recently announced its investment in Advanced Logistics , a marine and logistics management software company. Advanced Logistics, provides a full suite of web-based logistics management applications designed to systematically manage materials, shore bases, marine transportation, personnel, aviation and land transportation. The software technology provides the ability to efficiently transmit data between a vessel and the shore (accessible through a web interface in near real time) via a variety of satellite communication pipelines. Financial arrangements between the two companies have been kept confidential. As a result of its investment, The ASCO Group will use this logistics management technology to further enhance its service offerings. Jeffery Svendson, Advanced Logistics President and CEO, will remain majority stockholder. “Our real-time technology enables our customers to translate acquired data into useful information and then transform that information into useful knowledge for improved decision making,” said Svendson. “Harnessing information technology in this manner offers enormous opportunities to enhance efficiency and productivity.” “This partnership provides growth opportunities for both companies and the ability to offer clients increased efficiency,” said Derek Smith, ASCO’s Chief Operating Officer. “ At ASCO, we want to reach new clients as well as provide more services to our current clients, particularly services which fit and complement our current portfolio. This partnership supports this ambition, and we look forward to working closely with Advanced Logistics to deliver more value for our oil and gas customers.”

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ICT

Honeywell launches Experion mobile access HONEYWELL HAS UNVEILED Experion Mobile Access, a powerful mobility application that provides secure remote access to Honeywell’s Experion Process Knowledge System (PKS) through mobile computing devices. Experion Mobile Access enables field operators to view and respond to live information Honeywell is now providing virtualisation technology for its from Experion PKS while they are on widely-used Experion process rounds or inspecting the plant. knowledge system (PKS). Operations teams, including field operators, are key stakeholders in operator-driven reliability (ODR) programmes undertaken by plants to reduce maintenance costs and increase operating efficiency. ODR programmes require field operators to become actively involved in basic and proactive maintenance activities that necessitate the use of real-time information from control systems such as process values, trends or alarms. To enable plant and field operators’ need for fast and easy access to plant data, Honeywell has developed Experion Mobile Access, which works securely with the Experion PKS architecture and Honeywell’s OneWireless Network. This software application provides seamless field data access for plants with complex processes and expansive footprints that rely on a large mobile operator staff for proper operations, and to support the availability of process equipment.

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ICT

FlexNet Manager for Tullow FLEXERA SOFTWARE, THE leading provider of application usage, has announced that Tullow Oil has selected FlexNet Manager for Engineering Applications as their Software License Optimisation solution of choice. FlexNet Manager for Engineering Applications delivers the most complete and meaningful insight into application usage to efficiently manage concurrent software licenses. It is used by six of the ten largest oil and gas companies in the world. Within a matter of only a few weeks, Tullow Oil’s investment in FlexNet Manager has already paid for itself in software license cost avoidance, maintenance savings and improved user productivity. Perhaps an unexpected benefit from implementing FlexNet Manager for Engineering Applications was the credibility it provided the IS team in the eyes of the engineers. With data in hand, the team is now able to have a conversation with line managers about why denials of service are happening, and discuss very easy steps users can take to avoid them. “Having the data gives you the confidence to have the business conversation with the line manager, because you can show you know exactly what’s going on,” said Tim Burke, Head of Global IS Operations at Tullow Oil.

Sonardyne recieves SPRINT order SONARDYNE INTERNATIONALK LTD has received an order valued at over US$3mn from international oil and gas turnkey contractor, Saipem. The order includes six SPRINT systems and associated acoustic positioning equipment making it Sonardyne’s largest sale of acoustically aided inertial navigation technology to date. SPRINT (Subsea Precision Reference Inertial Navigation Technology) will be deployed in April in the West Delta Deep Marine concession (WDDM). This natural gas field is situated about 90-km offshore the North-West Nile Delta, at water depths between 400 and 1,000 metres. Saipem is responsible for the engineering, procurement, construction and installation of a total of eight new subsea wellheads and relevant infrastructures, umbilicals and flowlines. Since its launch in 2010 SPRINT has been operationally proven to extend the operating limits and increase the efficiency of subsea operations when using Ultra Short BaseLine (USBL) and Long BaseLine (LBL) positioning systems. In the Sparse LBL mode that Saipem plans to operate SPRINT in at WDDM, surveyors will be able to obtain accurate high integrity positioning data with less equipment to deploy than full LBL. This will significantly reduce operation time and vessel costs. SPRINT tightly couples Sonardyne’s Lodestar INS platform with Fusion 6G, the industry standard LBL system. With known transponder positions, the Lodestar mounted on an ROV can use the ranges from one or more seabed deployed transponders to acoustically aid the INS and constrain error growth in the absolute position output. Commenting on the order, Sonardyne’s Vice President Europe and Africa, Barry Cairns said, “We are delighted that Saipem has shown its commitment to SPRINT. The company has been a major user of Sonardyne products for many years and this latest order is recognition of the major cost and time savings SPRINT and sparse LBL will bring to its field development projects.”

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We are delighted to announce to our numerous Clients and the industry at large that Tolmann Allied Services Company Limited has achieved ATLAS approval as an invigilation centre for OPITO International Minimum Industry Safety Training (IMIST). IMIST is an OPITO standard which supports the global oil & gas industry to meet safety initiative targets. Tolmann has always been in the fore front of delivery of internationally accredited safety training. Our Services include: Basic Offshore Safety Induction Emergency Training (BOSIET), viz: Offshore/Onshore Induction Training Helicopter Underwater Escape Techniques (HUET) Survival at Sea (SAS) Basic Fire Fighting Basic First Aid Others are: International Minimum Industry Safety Training (IMIST) Advanced Fire Fighting AED & Advanced First Aid Breathing Apparatus Wearers' Course Confined Space Entry Helicopter Landing Officer (HLO) Helicopter landing Assistant (HLA) Helideck Fire Fighting Helideck Team Member Training Offshore Lifeboat Coxswain Personal Survival Swimming Search and Rescue Standby Fire Watch Swing rope Transfer STCW 95 Further Offshore Emergency Training (FOET) Dangerous Goods Awareness Training Proficiency in Survival Craft and Rescue Boats (PSCRB)