Oil Review Africa 5 2012 by Alain Charles Publishing

ORA 5 2012 Cover Final_cover.qxd 12/10/2012 14:51 Page 1

■ Geology - p40 ■ Gas - p42 ■ Exploration - p46 ■ Technology - p58

Volume 7 Issue Five 2012

www.oilreviewafrica.com

Africa

Covering Oil, Gas and Hydrocarbon Processing

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

Challenges and opportunities of Africa’s O&G Ghana’s local capability South Africa - benefits from Mozambique’s gas fields Managing the assembly line Corrosion management New generation vessels Understanding subsea separation Waste management

Nigeria independents breaking through Scott Aitken, Co-Chief Executive Officer Atlantic Energy. See page 20.

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

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Block 1 (Benin) Juan de Nova (T.A.A.F.) OML 130 (Nigeria)

Belo Profond (Madagascar)

By building strong and diverse joint venture partnerships, we pride ourselves in continuously developing our deepwater exploration capabilities which are being deployed in exploring over 60,000km2 of operated acreages in sub-Saharan Africa.

South Atlantic Petroleum

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■ Geology - p40 ■ Gas - p42 ■ Exploration - p46 ■ Technology - p58

Contents

Volume 7 Issue Five 2012

www.oilreviewafrica.com

Africa

Covering Oil, Gas and Hydrocarbon Processing

Challenges and opportunities of Africa’s O&G Ghana’s local capability South Africa - benefits from Mozambique’s gas fields

Columns Industry news and executives’ calendar

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

Nigeria independents breaking through

Managing the assembly line

Corrosion management New generation vessels Understanding subsea separation

Analysis

Waste management

Africa’s O&G: Challenges and opportunities

Interview with Rolake Akinkugbe, head of EcoBank’s energy research.

Gas grabs the headlines again Crude markets: Low expectations or high risk? Who benefits from the east coast gas bonanza?

12 14 16

Scott Aitken, Co-Chief Executive Officer Atlantic Petroleum. See page 20.

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

A leading light in Nigeria’s upstream industry is Oando plc, the country’s biggest indigenous integrated energy player.

Country Focus Nigeria

After years in the shadows of the international oil companies, Nigeria’s independents are breaking through. Deizani Alison-Madueke explains the PIB.

Ghana

Local capability in all aspects.

South Africa

Mozambique’s gas fields - a boon for Mossel Bay’s gas-to-liquids refinery?

Libya

Libya targets oil production to increase to 1.8mn bpd in 2013.

E&P News and developments

Drilling giants reach new depths as offshore exploration evolves.

Downstream News and developments

A round-up of recent downstream news from around the region.

Editor’s note JUST AS THE 20th century was the age of oil, the 21st could prove to be the age of gas. The east coast of Africa has yielded a series of huge discoveries over the past couple of years, with the biggest finds offshore Mozambique, and now Tanzania. The threat of piracy might loom large, but it has not prevented a new scramble for east Africa, led by some of the world’s biggest oil companies. Suddenly Mozambique and Tanzania, which until recently did not even feature on the world energy map, have become some of the gas industry’s hottest real estate. And with the region still relatively unexplored, there could be plenty more where that came from. Meanwhile, on the west coast, The Nigerian draft Petroleum Industry Bill has been hailed as a landmark opportunity to introduce a new era of reform in the country’s oil and gas industry, where the biggest beneficiaries will be the indigenous companies, who are already breaking through the shadows to compete with the IOCs. In Ghana too, steps are being taken to increase the efforts to enforce the government’s local content policy.

Logistics Managing the assembly line

Logistics remains one of the greatest tests oil companies face in Africa, especially in tough operating areas like the Niger Delta.

Technology Corrosion Management

Long-term coating solutions to stop CUI. A step change in corrosion monitoring.

Deep well challenges: The hunt for black gold Understanding subsea separation

60 68

Disposing of the unwanted elements brought to the surface during o&g production.

New-generation vessels

A new generation semi-submersible vessel is changing the game. An advanced vessel for West African pipelay.

Innovations

Environmental From ‘waste problem’ to ‘valued resource’

The Seven Borealis helideck is notable as the largest offshore helideck in production.

Managing Editor: Zsa Tebbit - Zsa.Tebbit@alaincharles.com Editorial and Design team: Bob Adams, David Clancy, Andrew Croft, Ranganath GS, Kasturi Gupta, Prashanth AP, Meenakshi Nambiar, Genaro Santos, Nicky Valsamakis, Julian Walker and Ben Watts

Africa

Covering Oil, Gas and Hydrocarbon Processing

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Oil Review Africa Issue Five 2012 3

Industry News & Events

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Executives’ Calendar 2012 OCTOBER 10-12 12-14 16-18 16-18 17-18 22 - 25 23-24 23-25 24-26 29-30 29-2 Nov

Upstream & Downstream Oil and Gas Expo 2012 Oil and Gas Recruitment TOG Lagos Power DRC Oil & Gas FORUM Artificial Lift Conference and Exhibition Oil & Gas Upstream Logistics & Supply Chain Conference 2012 Practical Nigerian Content Tanzania Mining, Energy/Oil & Gas and Infrastructure Indaba Global Energy 2012 18th African Oil Week

ABUJA CAPE TOWN TRIPOLI LAGOS KINSHASA CAIRO JOHANNESBURG PORT HARCOURT ARUSHA GENEVA CAPE TOWN

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Algeria Future Energy Logistics West Africa ADIPEC 2012 Power-Gen Africa 2012 Nigeria Oil & Gas Exploration The East Africa Oil and Gas Summit OPITO’s Third Global Conference to Focus on Managing the Safety Chain MPC 2012 Sudan Oil, Gas and Energy Exhibition Côte d'Ivoire Oil & Gass World LNG Summit Oil & Gas Recruitment Summit

ALGIERS LAGOS ABU DHABI JOHANNESBURG LAGOS NAIROBI

www.algeria-future-energy.com www.cwc-logistics.com www.adipec.com www.powergenafrica.com www.nape.org.ng www.eaogs.com

ABU DHABI TRIPOLI KHARTOUM ABIDJAN BARCELONA LONDON

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7th Sub Saharan Africa Nigeria Oil & Gas

CAPE TOWN ABUJA

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Mozambique Gas Summit Offshore West Africa ARA Week 2013 5th African Petroleum Conference and Exhibition

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Africa Oil Week to reveal African future WITH OVER 900 delegates from 75 countries and 85 presentations from leading speakers representing independents, national oil companies, governments, licensing agencies and banks, the 19th Africa Oil Week will take place from 29 October - 2 November 2012 at the the Pavilion Conference Center in Cape Town, South Africa. Pavilion Conference Centre in Cape Town.

4 Oil Review Africa Issue Five 2012

The Global Pacific & Partners' event will be held along with the 14th Scramble for Africa Strategy Briefing, the 47th PetroAfricanus Dinner, the 9th African Independents Forum and the 19th Africa Upstream Conference, ending with the traditional 'braai' (barbeque) on the Cape waterfront. Showcase presentations will be made by key companies and investors in Africa. For instance Dr Duncan Clarke, chairman and CEO of Global Pacific & Partners, will talk about future opportunities for independents in Africa. During the Upstream Conference new explorations and discoveries in Equatorial New Guinea, Nigeria, Mozambique and the Maghreb countries will be revealed. Executive vicepresident, Ian Cooling of Anadarko will tell of the exploration journey his leading super-independent made across the continent during the PetroAfricanus Dinner. Many of the leading players involved in the Eastern Africa acreage and gas boom are either on the speaker programme or have registered as delegates and exhibitors.

Trafigura signs $500mn Zambia oil contract ZAMBIA HAS AWARDED a US$500mn contract to Trafigura, to supply the country with petrol and diesel for one year, according to energy permanent secretary, George Zulu. Trafigura will supply Zambia with 216mn litres of petrol and 21mn litres of diesel during the contract period starting from October, Zulu said in a statement. “The country is now assured of a stable and continuous supply of fuel,” he said. Zulu added that the government was still talking to bidders for a separate contract to supply Zambia with 1.4mn tonnes of oil over two years.

S01 ORA 5 2012 Start_Layout 1 02/10/2012 15:53 Page 5

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Industry News & Events

S01 ORA 5 2012 Start_Layout 1 02/10/2012 15:53 Page 6

Tanzania’s TPDC ‘may split into two’ A TANZANIAN PARLIAMENTARY committee chief has said the country’s Petroleum Development Corporation (TPDC) could be split into a regulator and a national oil company under impending legislative reforms. "TPDC, as it is now, has massive conflict of interest as it is both a regulator and investor at the same time ... This creates a lot of inefficiencies," Zitto Kabwe, chairman of the parliamentary public corporations accounts committee, which oversees the running of state agencies, told Reuters. The region's second biggest economy has said it expects to have the country's first-ever gas policy in place in November and is drafting a natural gas utilisation master plan and legislation to regulate the industry. A keenly-awaited deep-water licensing round originally scheduled for September has been postponed pending a parliamentary vote on the new gas policy. Zitto said the auditing of actual costs incurred by oil and gas companies was a big challenge facing the sector. "The proposed national oil company must take up government shares in private companies with oil blocks, while the regulatory authority must enter into contracts and manage these contracts, including the auditing of contracts," he said. Many industry alarm bills were ringing when newly-appointed Minister of Energy & Minerals, Sospeter Muhongo, declared a review of all oil and gas contracts entered into by the TPDC. Some politicians and civil societies have called for a moratorium on the issuance of new oil and gas exploration rights until Tanzania can effectively manage its gas reserves. In June, Tanzania nearly tripled its estimate of recoverable natural gas resources to up to 28.74tcf from 10 trillion following recent major discoveries.

6 Oil Review Africa Issue Five 2012

Shell cashes in OML 34 chips SHELL HAS NETTED US$400mn from the disposal of its stake in Nigerian onshore block OML 34 after completing the sale to an indigenous consortium as part of its divestment of assets in the volatile Niger Delta region. ND Western, which comprises Niger Delta Petroleum, Walter Smith and Petrolim, is acquiring Shell’s 30 per cent interest in the lease, having also gained a 15 per cent stake from Total and Eni to give it a total of 45 per cent. Nigerian Petroleum Development Corporation will assume control of the block with a 55 per cent stake inherited from its state-run parent NNPC. OML 34 covers 950 sq km in Delta State and includes the Utorogu, Ughelli and Warri River fields and related facilities, with combined production of about 300 mmcfd

of gas and 15,000 bpd of oil and condensate. The latest disposal by Shell follows the recently completed US$100mn sale of its interest in OML 40 to Elcrest. The OML 34 sale is the seventh such transfer of Nigerian leases carried out by the Anglo-Dutch supermajor since 2010 as it curbs its exposure in the troubled oil producing region, where its operations have been hit by militant activity and crude theft as well as environmental issues. However, Shell said in a statement that it “remains committed” to maintaining a long-term presence in Nigeria, both onshore and offshore.

Hot tapping success offshore Angola PIPELINE EQUIPMENT AND services firm TD Williamson (TDW) has announced the successful completion of a hot tapping operation offshore Angola on behalf of Ponticelli Angoil The project, which was TDW’s first in Angola, has created a point that will allow a live flare line to be safely connected to a deposit line attached to a floating production, storage and off oading (FPSO) vessel. Rudy Lenom, project coordinator for TDW in Africa, explained, “By connecting the two lines, the operator will be able to burn – or flare – any excess associated natural gas that is released from the oilfield during production.” Despite the cramped working conditions upon the FPSO vessel, TDW took a total of three days to

complete the project, and production was at no point shut down. Ponticelli Angoil project manager Herve Cardeau said, “With the requirement that the hot tap operation be carried out quickly and safely without shutting down production, we were extremely satisfied with TDW’s ability to achieve this so efficiently, especially in such a small space. “It meant that we realised considerable savings in time and costs, especially in comparison to the costs that would have been incurred had we been required to shut down the line, even for a few hours.” Looking forward, Ponticelli Nigeria Ltd has commissioned TDW to carry out a series of hot tapping operations offshore Nigeria.

Liberia approves Seagull security training MARITIME TRAINING SPECIALIST Seagull, has secured Liberia’s approval for its unique security training package. Liberian approval comes little more than a month after Seagull announced that it had been awarded Norwegian Maritime Authority (NMA) approval for the new security training package, which is to be made available in October. Receiving Liberian approval so shortly after getting NMA approval underscores industry recognition of the importance of Seagull’s courses in ensuring seafarers are trained properly in all security matters. Shipowners can now be confident that their seafarers can demonstrate the necessary competency and proficiency. The package complies fully with the Manila amendments to the STCW Convention and Code, whose revised version introducing more stringent requirements for onboard security training with particular regard to attacks by pirates came into force in January this year. Under the amendments, all seafarers must have approved ship security training, varying according to their level of responsibility. They must receive generic security awareness and familiarisation training, while those with specific security-related roles must have appropriate

training for their role. The new Security Onboard training system offers three courses certified by Norwegian classification society Det Norsk Veritas through the SeaSkill programme. Seagull has developed two new CBT training levels. Level 1 addresses security-related familiarisation and awareness for all seafarers and Level 2 covers the requirements of seafarers with designated security duties. The existing SSO course, the designated Level 3 of the Seagull Security Onboard training system, has also been updated. Level 1 includes two e-learning modules; one on security awareness and one on piracy and armed robbery. These are backed up by a work book including a security familiarisation checklist. Level 2 comprises an onboard course for personnel with security duties, which includes the same two e-learning modules on security awareness, and on piracy and armed robbery. Level 3 training comprises the same two modules as Level 1 and 2, CBT 115 Security Awareness and CBT 156 Piracy and Armed Robbery, with the addition of a specific SSO e-learning module and workbook. This is delivered through the CBT 121 Ship Security Officer course.

S02 ORA 5 2012 News_Layout 1 02/10/2012 17:41 Page 7

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Industry News & Events

S02 ORA 5 2012 News_Layout 1 02/10/2012 17:41 Page 8

PetroSA acquires stake in Jubilee field

Total buys into Mozambique’s Rovuma Basin

PETROSA, SOUTH AFRICA'S national oil company, has purchased Sabre Oil and Gas Holdings for an undisclosed amount, giving the company a stake in Ghana’s offshore Jubilee field The company also bought out Sabre’s interest in the Deepwater Tano and West Cape Three Points blocks, in Ghana. The Jubilee oil field is located 60 km offshore and is the largest field in Ghana, with total proven reserves of around 600mn barrels. The Deepwater Tano and the West Cape Three Points have existing oil and gas discoveries, for which development plans are in progress, according to PetroSA. Consent for the purchase was granted by Ghana’s energy minister, Dr Joe Oteng-Adjeim, and followed a bidding process that shortlisted PetroSA along with two other international oil companies. PetroSA’s chief executive officer, Nosizwe Nokwe-Macamo, said the acquisition was part of the company’s strategy to increase its African footprint. “This deal provides PetroSA with a unique opportunity to establish a presence in this highly prospective region,” said Nokwe-Macamo. “We are very happy to be working with reputable partners such as Anadarko, Kosmos, Tullow and, of course, our counterparts, the Ghana National Petroleum Corporation. This deal provides PetroSA with a unique opportunity to establish a presence in this highly-prospective region.”

TOTAL HAS ANNOUNCED that it has expanded its presence in Mozambique thanks to a farm-in agreement with Petronas that will see it acquire a portion of the Malaysian state-owned oil company's interest in the Rovuma Basin. The deal will see Total take a 40-per cent interest in the production sharing contract that covers offshore blocks Area 3 and Area 6 that are located within the Rovuma Basin, while Petronas will remain operator of the blocks. The two blocks cover an area of approximately 15,280 sq km with water depths of up to 2,500 m. While Total is already active in Mozambique and other countries in East Africa, the deal is further confirmation of the region's status as an increasingly-important source of hydrocarbons. This year has already seen a six month-long takeover battle between Royal Dutch Shell and Thailand's PTTEP for the ownership of Cove Energy – which holds an 8.5-per cent stake in the Barquentine gas field in Rovuma offshore Area 1 (where the operator is Anadarko). Both Shell and PTTEP see the potential for LNG developments in Mozambique. "After Kenya and Uganda, Total is entering into the southern part of the prolific Rovuma Basin, whose oil potential might equal the gas potential of the northern part," said Jacques Marraud des Grottes, Total's senior vice president for exploration and production in Africa, in a statement. "The farm-in significantly strengthens our long-term presence in exploration and production in East Africa. Exploration wells are expected to be drilled shortly."

Kenya seeks Nigeria’s help in O&G sector KENYA IS SEEKING to learn from Nigeria how to effectively manage oil revenues, according to the Energy Minister Kiraitu Murungi, who made this disclosure when he led a delegation to the Department of Petroleum Resources (DPR), National Petroleum Investment Management Services (NAPIMS), and Nigerian Association of Petroleum Explorationists (NAPE) in Lagos. According to him, “Kenya has just discovered oil and we are here to learn a good lesson from Nigeria. We are taking a copy of the country’s Petroleum Industry Bill (PIB) so we can use it to modernise our exploration and petroleum act. We have to build our capacity and improve our management efficiency to make sure that oil revenues are properly managed between the multinationals, governments and the host

communities,” he said. According to the Chairman/CEO of Camac Energy, Dr. Kase Lawal, where Kenya is today, with the discovery of oil and now gas, they are far ahead where Nigeria was when first oil field was found in Oloibiri in 1952. He pointed out that the minister knew what he wanted for his country and how he wanted to utilise the little opportunity of exploration in his country as there was really nothing much to teach him as both countries were sharing experiences as fellow Africans in a partnership mode. According to him, “we are sharing information as partners and they are taking the best practices on some of the places where we didn’t do too well at the beginning and they are actually coming up with a blueprint on the benefit of the country’s oil and gas sector.

“What CAMAC has done since its existence as one of the pioneers in indigenous companies in Nigeria is that we have expanded into many African countries like Angola, Gabon, Liberia and Ghana and Kenya and we are very instrumental in the local content vehicles. “The experience with Kenya is a natural one. One where they have done a lot of work with best practices in other countries. So, coming to Nigeria as the largest producer of oil and gas in Africa is one that essentially summed it all. Osten Olorunsola, Director Nigerian Department of Petroleum Resources, said: “The lesson we have learnt right now is that Nigerians need transparency and accountability in everything we do because other African countries are also watching us and learning from us.”

Uganda’s oil reserves up to 3.5bn barrels THE UGANDAN GOVERNMENT has said that its estimated oil reserves in the Lake Albertine Rift basin have increased from 2.5 to 3.5bn barrels, following months of rigorous appraisal and drilling activities. Ernest Rubondo, the head of the country's Petroleum Production and Exploration department, said that over the past several months oil exploration companies have appraised various wells in blocks 1 and 2, boosting the potential of the basin. "I can confirm that the our reserves have increased to 3.5bn barrels," Mr. Rubondo

8 Oil Review Africa Issue Five 2012

said, adding that the basin still has potential for more discoveries. Blocks 1 and 2 are operated by Total and Tullow Oil respectively. Uganda first announced commercial oil in the basin in 2006, but the East African nation is yet to start crude pumping amid a spat with companies over the oil production plans and refining options. Tullow, Total and Cnooc said earlier this year that they would invest at least US$10-12bn to develop the oil fields by 2017. The government has appointed a panel to

review and approve the oil development plans but it has not yet indicated when the plan is likely to be approved. According to Tullow, first oil output is expected 36 months after the approval of the plan.

S02 ORA 5 2012 News_Layout 1 02/10/2012 17:41 Page 9

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Analysis

Rolake Akinkugbe heads the pan-African bank Ecobank’s energy research. She talked with Oil Review Africa’s contributing editor, Stephen Williams, about this hugely exciting era for Africa’s hydrocarbon industry.

Africa’s O&G: Challenges and

opportunities W

HAT’S YOUR VIEW of the continent’s oil and gas sector’s prospects?

The world today is consuming around 89 mn bpd of oil, and, in the general context that we are running out of conventional sources of oil, in about four year’s time, we will need to find around an extra 20mn bpd – and that is on the assumption that there is no level of GDP growth globally. However, if we see any economic growth we will see an increase in global oil demand, and that’s very interesting from an African viewpoint because of its emerging, frontier markets. I think African sources of oil, particularly frontier sources of oil, are becoming increasingly more attractive. What makes Africa’s frontier markets so interesting? Africa is under-explored, and so investors find that attractive. It’s a lesser known terrain for explorers. It’s also the competition landscape – you have your traditional major international oil companies, but you also have independent explorers. Tullow, for example, and the likes of Anadarko, African Petroleum, African Oil Corporation, and all the others. Then you have the indigenous oil players, but you also have national oil companies from emerging markets. Clearly, Africa offers a nearlevel playing field and offers room for entry for all sorts of players. I know you have strong views of the way the extractive industries are viewed. Would you expand on that? This is something I feel very strongly about, particularly as someone who covers the oil and gas industry. So many people see the extractive

industry in Africa as just an extract and export model where the local population and economy does not feel any benefit.. But I see so much potential for the energy sector in Africa and I think that’s something governments need to tune into. I see gas in particular as presenting huge benefits to African economies. It will gradually account for a growing proportion of the region’s energy mix and gas, more than any other hydrocarbon, has the greatest potential impact for economic transformation. I’m thinking gas for power generation in Africa, gas for fertiliser, and gas for petrochemicals. African governments are moving towards a model where they impose a supply obligation, where they say a percentage of gas production has to go into domestic supply, and the challenge of that is you need to have a regulatory framework that supports the policy, so utility tariffs have to be competitive, but I know some governments are moving towards increasing tariffs over time.

I’m thinking gas for power generation in Africa, gas for fertiliser, and gas for petrochemicals. This raises the subject of the new gas discoveries offshore Tanzania and Mozambique. Yes. East Africa now has almost 100 trillion cubic feet of gas which will soon start to rival Africa’s largest gas reserves holder, Nigeria, which has 186 tcf. The key challenge for gas as a commodity in Africa, is whether governments can think strategically.

Rolake Akinkugbe, Head of Oil and Gas Research at Ecobank.

I think East Africa has a real advantage because of its geographic proximity to Asian markets. It would make sense to develop some sort of energy hub. I think that there are lots of opportunities for African resources and we’ve seen a high level of M&A transactions. It’s actually interesting to watch the whole play for East African assets. For me, the regions within Africa, where I’m relatively bullish about prospects, are the traditional Gulf of Guinea region and south of the Gulf of Guinea, where there’s been a lot of pre-salt exploration off the coasts of Namibia, Angola and Congo (Brazzaville), as well as the East Africa Rift system and the Rovuma Basin area – these are seeing a great deal of activity. What are the principle challenges? It’s the same issues that crop up time and time again. How do you effectively manage revenue that comes from oil and gas, how do you ensure transparency, how do you ensure that there’s some sort of local value creation for African countries that produce oil and gas? These would be my thoughts.

Agri and Statesmen team up in Africa AUSTRALIA’S AGRI ENERGY has entered an agreement with Canada-listed Statesman Resources to pursue oil and gas opportunities in Africa. As part of the agreement Agri will acquire a 49.9 per cent interest in Statesman’s wholly-owned subsidiary, Statesman Africa, which was recently awarded a 75 per cent interest in Block 14 in north-west Sudan. Agri said the minimum expenditure over the three year term of the exploration production sharing agreement for Block 14 was US$12mn and added it had advanced Statesman US$800,000 to provide interim funding and would form part of its overall 49.9 per cent funding obligations. “North-eastern Africa represents an area of significant growth and activity in the oil and gas sector and the 100,000 sq km exploration block secured in northern Sudan is a significant entry point for a

10 Oil Review Africa Issue Five 2012

company of our size,” Agri managing director Gregory Channon said. “We look forward to working with Statesman and our other partners in Block 14 and are excited about the potential of this block which is close to many of Africa’s largest producing regions.” Agri said Block 14, which lies adjacent to the border with Egypt and Libya, was underexplored with only partial gravity coverage, 1200 km of 2D seismic and one shallow stratigraphic well on the block. It added the prospectivity of the block was defined two deep untested sub-basins, the Mourdi and Mesaha, with the previous operator Sudapet identifying a multi-billion barrel resource inventory. Preliminary work carried out by Statesman has indicated the largest lead could hold a mean potential resource of 600mn barrels.

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Analysis

It will be many years before the “shale gale” blows through domestic gas markets in Africa. But LNG exporters are already taking note of its possible effects.

Gas grabs the headlines

again T

HE INTERNATIONAL GAS market is being transformed by the development of vast new reserves of ‘unconventional’ supplies in North America. Huge discoveries elsewhere are almost certain too, but environmental concerns are holding back their exploitation. As a result different regional gas markets are being formed which have profound implications for the commercialisation of Africa’s surplus gas. BP’s latest annual energy survey* stresses the key role the hydraulic fracturing revolution played in turning around the gas market in the USA in 2011 – but so far has made little impact elsewhere. Indeed in South Africa – probably the best hope for shale gas anywhere in SSA – a moratorium has recently been placed on development because of environmental fears, just as in France. In both countries the search continues nevertheless. Already-high gas prices in most other countries increased broadly in line with oil last year, with China accounting for by far the largest increase in world gas consumption. In 2011 this clean and flexible fuel supplied nearly one-quarter of total global commercial energy consumption, almost precisely the same as in the 12 months before. And in that year Africa as a whole supplied 6.2 per cent of the world’s gas supplies, consuming in return only 3.4 per cent and thereby making yet another huge contribution to the security of energy supplies.

Significant local discoveries As significant local discoveries in both East and West continue to be made this positive input to evening out the world’s gas imbalances is certain to grow; Africa simply does not have the distribution infrastructure to absorb much more, however many new gas-fired power stations are built. Algeria, Egypt, Nigeria and welcomed-back Libya continue to dominate the regional supply pattern. So where, at a time of unprecedented change occasioned by the discovery of brand new supplies, is the world gas market – which relies so much less on international trade than oil, despite the earlier LNG revolution – now headed? By 2035 the influential International Energy Agency calculates that global output could increase many times over, much of this growth being seen right here in SSA in countries such as fast-growing Tanzania. But for now, offsetting this enormous win-win potential, there is a vast and potentially disruptive difference growing between gas prices in North America, Europe and the Far East, and in how they are set. Right now

12 Oil Review Africa Issue Five 2012

The drillship Ocean Rig Poseidon and support vessels at the Zafarani location.

indexation against the price of crude oil prevails. Energy history tells us that such an imbalance cannot last. It is far from certain that the so-called shale gale will blow across all continents, although China could – eventually – rival today’s USA as the most significant country to be affected. What seems unlikely for the present is that the newly-formed Gas Exporting Countries Forum will succeed in stitching together a cartel along the lines of the highly successful OPEC organisation, which continues to have such an impact on oil production levels and therefore earnings in Algeria, Angola, Libya and Nigeria. There are simply too many alternative major sources of gas supply on tap, and the market as a whole is too much disturbed by the recent vast increase in North American and potentially global availability to permit such a restrictive development.

LNG is Africa’s major contribution Africa’s major contribution to the world’s gas balance is undoubtedly in the form of liquefied natural gas. ‘Invented’ in the USA but pioneered by Sonatrach and Shell in Algeria this strategically located Mediterranean country remains the continent’s largest all-forms supplier, although Nigeria is now number one in LNG – frozen gas is much more costly to deliver than by pipe. But it’s much more flexible in terms of where it can be sent to, including diversion at short notice, so LNG can

So where, at a time of unprecedented change occasioned by the discovery of brand new supplies, is the world gas market now headed? be used to plug energy gaps. Its huge value in this respect alone was clearly seen after Japan’s major nuclear accident and resulting energy shortfall last year. As new projects shape up in both East and West – the latest in Tanzania - the problem for Africa’s existing and potential exporters remains one of potential global over-supply. Not only is Australia moving up to displace market-making Qatar from its current top spot, but some US receiving (re-gasification) terminals are now, because of the fracking revolution, being converted at relatively low cost into joint liquefiers and exporters too. The first of these turned-around plants could be in business by 2015, taking advantage of the massive regional differentials that now exist in world gas prices. Further down the line ‘floating LNG’ (processed in movable barge-mounted plants, excellent for exploiting stranded resources here in Africa) and

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“But for that to happen,” it warned on 29 May, “governments, industry and other stakeholders must work together to address legitimate public concerns about the associated environmental and social impacts.” “If [these] are not addressed properly, there is a very real possibility that public opposition to drilling … will halt the unconventional gas revolution in its tracks.” At the same time it proposed a matching set of ‘Golden Rules’ underlining the importance of full transparency, measuring and monitoring environmental impact with the engagement of local communities, improved project planning, and so on. These will certainly increase development costs, the OECD Agency warned, but these could in many cases be offset by lower eventual operating costs. In short, another handy win-win situation seems to be on its way. “Just as the 20th century was the age of oil, the 21st could prove to be the century of gas” said the UK weekly Economist in a major survey of this key fuel on 14 July 2012 Pulitzer Prize-winning analyst Daniel Yergin agreed in his earlier study The Quest” (IHS Cambridge Energy Research Associates, 2011), in which the “truly global” nature of today’s gas market is very positively commented on. However to benefit from all this change the

Analysis

eventual development of Russia’s huge offshore Shtokman field suggest even more market disruption could be on the way. On the positive side China could become one of the world’s largest buyers, with something like 20 reception terminals for LNG at various stages of planning, construction or operation currently in the frame. Japan and South Korea are far ahead in the lead as customers currently. As the global trade in LNG continues to grow – again by more than 10 per cent last year – the level of price competition can only rise at the same time, putting off potential entrants to this capitalintensive and -rising industry which can make such lucrative use of otherwise unsalable gas, as in established Equatorial Guinea. Last year. according to BP’s Statistical Review, Africa’s total LNG exports amounted to 57bn cm, just under 19 per cent of the global total. The figure would have been even higher if Libya’s exports to Spain not been temporarily lost. The US, southern Europe and various prosperous industrialised countries in the Far East are the principal customers for these fast-growing supplies, with Nigeria clearly in the regional lead. Faced with all this mostly happy change the IEA has sown the idea of a coming ‘Golden Age of Gas’, fuelled by the massive recent increase in known resources.

Gasol aims to develop the LNG market in West Africa.

Just as the 20th century was the age of oil, the 21st could prove to be the century of gas. current embarrassingly inconvenient regional price differentials simply must be addressed, and to achieve this Africa’s gas exporters – primarily of LNG, but the North’s pipeline operators too – have got to be more fully involved in a pricesetting process that seems increasingly anachronistic. Right now they don’t have anything like a big enough say. ■

bp.com/statisticalreview

Oil Review Africa Issue Five 2012 13

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Analysis

The Platts 5th Annual Crude Oil Markets Conference and Forum took place earlier this year. However, as Phil Desmond reports, quite a few of the event’s expert assessments are likely to remain true for some time.

Crude markets: Low expectations

or high risk? T

HE PLATTS 5TH Annual Crude Oil Markets Conference and Forum in London in May, organised by Platts, a leading global energy information provider and publisher of benchmark price references, was sub-headed 'Exploring Regulatory Change, Benchmark Evolution, and Shifting Fundamentals'. However, the topics discussed were often appropriate not only to esoteric oil terminology but to mainstream news headlines. The US shale oil and gas bonanza, the effect of growing local demand on Saudi Arabia’s exports, and fuel efficiency are all obviously relevant to the price and production of oil in the years to come. But there are less obvious factors: the Fukushima disaster has increased Japanese reliance on oil and gas; Chinese development — and hence its reliance on oil — may eventually stall as its population ages; Greece leaving the euro could affect the rest of Europe, bringing another recession and diminished oil demand; and if Iran closes the Straits of Hormuz the effect on oil transportation could be catastrophic. Ruth Cairnie, EVP, Strategy and Planning, Royal Dutch Shell tried to take on the difficult task of summarising diverse megatrends and assessing long-term developments in a keynote address entitled ‘The New Upstream Environment — 'Understanding New Risks and Capitalising on Future Opportunities'. Some trends are, on the face of it, easy to summarise. We can, for instance, confidently expect a global surge in demand and global population growth. With these changes will come stresses — on water and food supply and, by extension, energy. However, “by 2050”, Cairnie said, “we will have to supply over 50 per cent more energy and do that at the same time [as] reducing greenhouse gas emissions to half the levels they were at the beginning of the century”. Renewable energy will play a part, but 40mn barrels of oil equivalent per day will still need to be developed just to maintain production. Could Iraq, Brazil and the Arctic — to name just three potential oil hotspots — supply a significant part of that? And what about the US shale oil and gas bonanza? However, while there are trends that we can predict, there are also geopolitical events that we may not have expected that could affect oil supply and price. Who would have foreseen the Arab Spring, the Eurozone crisis, and ‘black swan’ events like Fukushima and Deepwater Horizon? Meanwhile, an emerging trend — the diminished public trust in oil companies over safety and the environment — will need to be balanced against the unavoidable push towards more challenging hydrocarbons and frontier operating environments, as well as cost escalations and skills shortages. One likely outcome is that limited resource access and growing competition may eventually require new and innovative partnering strategies between IOCs and NOCs. Not surprisingly perhaps, it doesn’t look as though the price of crude will tumble. That was the view of Sabine Schels, senior director and global commodity strategist, Bank of America, Merrill Lynch, in her talk entitled 'Oil Market Dynamics in 2012 — Stability or Greater Volatility on the Cards?' “High oil prices are here to stay for quite some time,” was Schels’ summary.

Oil supply facing great pressures Johannes Benigni, Managing Director, JBC Energy, focused on such trends as the increasing effectiveness of sanctions again Iran, Iraq’s inability to hit its output targets, and local and international pressure on Saudi Arabian supply, as well as the fact that non-OPEC crude supply is also finding it difficult to fill the gap. Oil supply is clearly facing great pressures. On the other hand, demand has declined and will continue to do so in the US and OECD countries. But not all of this decline is down to belt-tightening. As Peter Hughes, director head of energy practice, Ricardo Strategic Consulting, pointed out, 55-60 per cent of oil demand is from one sector: transportation. He predicted that car fuel efficiency

14 Oil Review Africa Issue Five 2012

World demand will rise this year and probably for some years to come. will improve markedly in all regions and could be a major factor in limiting oil demand over the long term. Nevertheless world demand, led by pretty much everywhere else, including Africa and the Middle East but especially China, will rise this year and probably for some years to come. So where are the extra barrels that will be needed coming from? Ruth Cairnie of Shell mentioned the Arctic of course, and there are expectations that shale oil will offer one to three million barrels a day by 2020. This is a very imprecise estimate but that’s because, as Benigni said, “every shale oil development is different”. Iran’s potential is clearly unlikely to be realised. Nor is that the only worry in a region where security issues, sanctions, civil war and piracy are, or could be, concerns. World refining capacity, ironically, is abundant. IEA Oil Industry and Markets Division head David Fyfe referred to “a tidal wave of new capacity being built in the emerging markets”. But refining is hardly the IEA’s major concern right now. Like most of us, it is focused on the supply side where hold-ups in Libyan supply and unexpected stoppages in non-OPEC producers got worse in early 2012, far outstripping the allowances (about 300-400,000 bpd) made by the IEA for factors like hurricanes and stoppages. Like everyone else, Fyfe’s presentation ('Oil Market Update: Has the Tide Turned?') cited “still fairly robust non-OECD developing market demand”. The odd thing is that global expenditure on oil seems higher than the level at which oil use should show signs of decline. So why isn’t it declining? Japan is easy to explain: LNG and oil are filling the nuclear power gap. However, many heavily import-dependent emerging markets are, it seems, “subsiding oil at the point of use”. “That’s why,” said Fyfe, “you can still have relatively robust growth in the face of $100 oil.” There was much more analysis at the conference, in the main incisive and well judged. But equally, speakers admitted that there was much they couldn’t predict; events like Fukushima, Deepwater Horizon and the Eurozone crisis all make that clear. However, access to expert opinion that can take a better than educated guess at the likely outcome of both long-term trends and shorter-term threats is at least a way to be ready for some of them. Which is why we need events like this one. ■

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Analysis

S03 ORA 5 2012 Analysis_Layout 1 02/10/2012 15:57 Page 16

First it was Mozambique. Now it’s Tanzania’s turn — or it could be. But, Vaughan O’Grady asks Marne Beukes*, who wants to buy natural gas from these two new arrivals on the gas supply scene? How much will be available? And how valuable is it in a world of multiple gas suppliers?

Who benefits from the east coast

gas bonanza? T

ANZANIA HAS FOLLOWED Mozambique into the natural gas big time, it seems. A recent note from IHS* energy analyst Marne Beukes on Statoil’s latest gas discovery off Tanzania is headed: East Africa Gas Bonanza Expands As Statoil Hits More Gas Offshore Tanzania. And yet Beukes points out, "This part of the country's offshore has been neglected in earlier drilling programmes." Why? “It is,” she explains, “more expensive to drill offshore and in the deepwater; you need the finance and expertise. The majors and supermajors have the ability — with a few exceptions for smaller companies like Kosmos which made the Jubilee discovery in Ghana. Only when the majors entered Tanzania from 2010 did exploration kick off.” Now of course exploration has gone even further; this is Statoil’s second gas encounter offshore Tanzania and with the company’s Tanzanian drilling programme just getting off the ground, the potential for more gas encounters in the Tanzanian part of the Rovuma Basin is seen as strong by IHS. But how strong compared to, say, Mozambique? “The Rovuma Basin only extends into the Tanzanian offshore for a few blocks, so nowhere near as large as in Mozambique,” says Beukes. On the other hand, exploration is still in its early stages in Tanzania and Statoil has made a sizeable discovery early on. Other wells have still to be drilled so the potential is fairly large but, says Beukes, “it remains to be seen if the discoveries are as big as Mozambique.” But does being neighbours in exploration of the Rovuma basin have possible downsides in geological terms? Could gas reserves migrate from one country’s claim to that of another? Probably not. Beukes says that hydrocarbon reserves are capped either by a fault or a salt cap, which is why they can accumulate over the years in the first place. That said, she adds, “If there is a reserve that crosses the border it can be a challenge but what often happens is that that area is declared a joint development zone (JDZ)”. This has happened in Nigeria and Sao Tome and could possibly be the basis of an arrangement between Ghana and Cote d'Ivoire.

Mozambique up and running Mozambican gas production is already up and running. Could that country’s experience be useful to Tanzania? It may in particular be able to offer some lessons in dealing with offshore threats from piracy. Perhaps that’s why Anadarko, which first

16 Oil Review Africa Issue Five 2012

The Rovuma Basin has one of the most prolific conventional gas plays in the world.

“I think we shouldn't rule out FLNG.“ signed an oil and natural gas exploration and production concession contract with the Mozambican government in 2006 and is currently designing the onshore liquefaction facility with its partners, has decided on the pipeline-to-onshoreplant option, rather than invest in the largely untried FLNG. “Eni is said to be considering FLNG, but then so did Anadarko.” Beukes points out. Eni is another major gas player and recently announced an enormous new offshore natural gas discovery. Still, she adds: “I think we shouldn't rule out FLNG. Remember that Mozambique does have issues regarding armed banditry at ports so even onshore is not entirely safe; however, this is a benign risk compared to maritime piracy.”

Well defined export market So where will this gas go? In fact the export market can be fairly well defined. “India, Taiwan and South Korea have already been mentioned as likely buyers but it could include other Asian buyers like Japan, depending on what their demand situation is like in the next few years,” says Beukes. Japan is arguably the wild card since the Fukushima disaster encouraged it to embrace non-nuclear power. Certainly Asia remains the most likely target

overall: the distance to many other markets would make them uneconomic to target and besides, North America wants to produce its own LNG on a large scale too — and clearly can. Whatever else happens, however, Tanzania will probably follow Mozambique into some sort of overseas markets. “I think the Tanzanian government has long been pushing for gas exports in the event of a sizeable discovery or discoveries,” suggests Beukes. Of course the international gas export market has changed. Qatar was able to arrange very advantageous term contracts for its LNG when it was the one big player. Today more players, more competition and more price pressure are now the norm. Or so it would appear. What happens as Papua New Guinea, Australia and others come on line to challenge East African supply? This is not an easy question to answer. IHS believes that Asian long-term demand (post-2020) is uncertain, and dependent on many factors like Chinese economic growth and Japan's continuous reliance on LNG to replace nuclear. At the moment, though, there is no reason to believe that long-term supply contracts are obsolete. In fact Beukes points out that Australian LNG projects have still been securing long-term projects. “There was the one for 25 years with Kansai and APLNG for instance quite recently. Also,” Beukes adds, “it depends on how the Mozambican LNG project developers — or any in the region — choose to market the gas output. Angolan LNG sells the gas on the international spot

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Beukes isn’t sure. There have been plans for many years for an integrated pipeline network in the region but it may be many more years before this actually exists, she says, suggesting that regional cooperation may only extend only as far as pipelines and gas-fired electricity networks. “Other than that the potential is limited,” she points out, “simply because if Tanzania's own gas reserves are enough to satisfy its own domestic needs — and maybe even export — there will be no need to trade in gas.” There’s the South African market of course, but, as we have already heard, it is going to cost a lot to ship offshore gas to that country's GTL facilities in Secunda and Sasolburg. “Other East African countries like Uganda rely more on hydropower than gas,” says Beukes, “and unless there is a sudden change in their energy policy to diversify sources I don't think the regional trade in gas will be that big.”

Threatening regulatory environment But if that isn’t a problem perhaps the potential for what IHS calls a "threatening regulatory environment" could be. Mozambique is already planning to hike the percentage the state company acquires in blocks and, says Beukes, “I see Tanzania often mirrors what Mozambique does — first Mozambique talks of changing fiscal terms

following discoveries, and then Tanzania and Kenya.” Thus the economics of gas production are hard to judge definitively just yet. Or indeed the skills contribution of the countries housing the gas. How ready are Tanzania and Mozambique in terms of skills to share ventures with foreign companies, given that neither have long-term experience? “Practically they are not,” Beukes says. “But often these types of countries will have their interest carried by the company they are partnering with, using their capital and skills. If talking about a joint venture between the two countries, again for upstream exploration this is likely to also involve a carried interest and the involvement of big companies.” Even in the downstream sector with pipelines, it seems, the governments will be relying at least for the finance and expertise on internationals. But it’s not as if Mozambique in particular is completely unused to dealing with big projects. As Beukes points out, “Mozambique seems to have been able to cope well with the rail and mining projects so far and can also use migratory labour from South Africa.” ■

*IHS is a leading source of information and insight in energy, economics, geopolitical risk, sustainability and supply chain management. www.ihs.com

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Analysis

market,” she points out , although Angola's output is much less than Tanzania’s will be. At the same time there is going to be a reasonable-sized local and regional market for Mozambican and Tanzanian gas. Gas can be piped to South Africa, for example, albeit at great expense due to the distance, and Tanzania does have some gas-fired electricity capacity. Nearby Kenya has industries that could switch to LNG as a source of energy. However, the local market will remain too small to use all the gas. Certainly, while some will be kept for domestic and power use, the bulk of Mozambique’s vast output of gas will be for the export market. The idea of a gas hub alongside Mozambique and (if gas is found) Kenya is surely an interesting concept. Tanzania will potentially be exporting at the same time as its neighbour so how about an East African gas hub? The idea of a gas hub alongside Mozambique and (if gas is found) Kenya is surely an interesting concept. On the face of it, the signs are good. There is already a history of economic and political co-operation through the East African Community (EAC), some linguistic overlap and a history of regional trade. And in any case, cooperation might be necessary to avoid destructive competition. But how much potential for constructive co-operation is there in reality?

S04 ORA 5 2012 Nigeria_Layout 1 02/10/2012 16:05 Page 18

Nigeria

After years in the shadows of the international oil companies, Nigeria’s independents are breaking through. Here’s our pick of the bunch.

Simply the

best Exploration & Production: South Atlantic Petroleum SOUTH ATLANTIC PETRLOLEUM’S (Sapetro) success story started soon after landing its first Nigerian block, OPL 246, about 150 km south of Port Harcourt, in 1998. This area included the huge Akpo find, which has now been hived off into OML 130, and is operated by China’s CNOOC. First production from the field started in 2009, with Akpo expected to reach peak production of 225,000 barrels of oil equivalent per day (boepd) shortly. Building on its Nigerian production success, the company has widened its footprint, first to neighbouring Benin, where it operates offshore Block 1, with first output from the re-developed Sèmè field due next year. Across the continent, it has also acquired an interest in a pair of blocks in the Mozambique Channel, which is now attracting huge investment following a succession of big gas finds. Perhaps unsurprisingly given this rapid rise to prominence - Sapetro is one of the country’s top indie oil producers - Sapetro is bullish about Nigeria’s policy to boost local content in the energy sector. “The local content act is a laudable act,” says Sapetro’s Hetty Nosa-Ehima. “While it is recognised that full compliance with the act may be challenging for the international oil companies initially, eventually it will become a durable mechanism to develop the industry with the indigenous resource being the key industry drivers.” Within the company itself, offshore development activity and the exploration of other assets elsewhere in Africa has led to huge capacity building, honing local skills and talent. And this is spreading through the industry, she reckons. “We have leveraged our understanding of the Act, which has enabled us to utilise some of our Nigerianbased service companies in executing work commitments on our other African assets.” Platform Petroleum Platform Petroleum is another successful Nigerian independent producer, lifting off in 2004 when it was handed the Asuokpu/Umutu marginal field as sole operator. Within a few years, Platform had brought the field - since renamed Egbeoma - into production, commencing maiden output in September 2007. The early development of the field, located in OML 38 in the north central Niger Delta, marked a triumph for the company and its financing partner, Newcross. The team tested and completed two wells, commissioned a 10,000 bpd

18 Oil Review Africa Issue Five 2012

Aerial view of the FPSO offshore the Akpo field.

In 2009, Platform formed a new joint venture, Seplat, with another small Nigerian independent, Shebah Petroleum. flow station and built a 48 km pipeline to link Umutu eastwards to ENI’s export Kwale facility. This pipeline would later be used by other operators to move oil from surrounding fields, netting the company a fee for its usage. By the end of 2011 the company was enjoying oil production from its investments of around 2,600 bpd. Austin Avuru, Platform’s founding chief executive, attributes the company’s success over the past decade to pure hard work and dedication. “We are not magicians,” Avuru was quoted as saying in a recent interview. “But we get things done.” But his team are clearly thinking bigger. In 2009, Platform formed a new joint venture, Seplat, with another small Nigerian independent, Shebah Petroleum. And with established French oil firm Marel & Prom behind them, the group took on upstream concessions from Shell, Total and ENI. Seplat landed an interest in OML’s 04, 38 and 41, three blocks in the onshore western Niger Delta covering about 2,650 sq km, with 30 wells and a production capacity of approximately 35,000 bopd and 110 mmscfd of gas. All the gas production from the assets is sold to the Nigerian Gas Company, through existing pipeline networks. Seplat’s production from these assets is around 16,800 boepd, which boosts Platform’s own net output by a further 3,696 bpd.

Mono Puli Another major independent is Moni Pulo Ltd (MPL). Founded by Dr Lulu-Briggs, Muni Pulo is the sole operator of OML 114. This covers a total area of 465 sq m with a cluster of 17 horizontal production wells and two water injection wells. Production is through two production platforms installed on the developed Abana field. MPL’s production assets also include the Agbani Floating Production Facility (FPF) complete with water injection facilities to process oil and gas from OML 114. The crude oil produced is transported via a 42km, 12 inch sub-sea pipeline to a Floating Production Storage and Offloading (FPSO) facility. The FPSO serves as our storage and offloading facility. "Being the sole operator of our asset OML 114 was at times a steep learning curve but it was worthwhile because we were able to acquire competencies and skills which have prepared us for the demands of the development of our three new oil blocks", said Lulu-Briggs. MPL has gone a long way to ensure compliance with the Nigerian government’s gas flare out policy. Produced associated gas currently being flared will be re-injected into a dedicated reservoir for storage. An injector well for this purpose has been drilled and completed. Gas compression facilities will be commissioned in the first quarter of 2010. The re-injection will continue until the time when the gas master plan of the company is ready for implementation. First Hydrocarbon Nigeria First Hydrocarbon Nigeria was established in direct response to the Nigerian government's policy to increase indigenous participation in the Nigerian upstream oil and gas sector. FHN started on a strong footing, and this can be traced to the backing of its parent company Afren. Its top

S04 ORA 5 2012 Nigeria_Layout 1 02/10/2012 16:05 Page 19

S04 ORA 5 2012 Nigeria_Layout 1 02/10/2012 16:05 Page 20

Nigeria

owned Nigerian company with the divestment of Petroman Oil Ltd. The company subsequently participated in the marginal oil field licensing round for indigenous companies and was awarded the Ibigwe field located in OML 16 by the Federal Government of Nigeria in 2003. The award was on a joint interest basis with Morris Petroleum and Waltersmith as the operator. Waltersmith executed a farm-out agreement with Shell Petroleum Development Company and its Joint Venture Partners including the NNPC in 2004 to effectively take over the field for development. In June 2008 Waltersmith commenced production and crude export from the concession area. "Our activities are grounded on the best business practices, good governance and strong commitment to social and environmental responsibilities for the benefit of humanity!"

Oando won the Nigeria best company of the year at NOG 2012 held in Abuja.

MPDC intends to begin aggressive exploration activities in deep offshore blocks. management looks like an Afren alumni and it has also "put in place a world-class Nigerian senior management with a proven track record of securing local and international financing for oil and gas assets in Nigeria, and also developing assets from exploration through appraisal development and production quickly." FHN's main asset is OML 26, located onshore in the Niger Delta, covering 480 sq km. The block has two fields that are currently in production (Ogini and Isoko), both of which offer large scale upside through implementation of a phased development programme and three discovered but as yet undeveloped fields (Aboh, Ovo and Ozoro). Significant additional exploration potential has also been defined on OML 26, with estimates of 615 mmboe gross unrisked prospective resources across multiple prospects that will continue to be worked on in parallel to and integrated with the development plans for OML 26. NPDC Ltd The Nigerian Petroleum Development Company (NPDC) Ltd is a fully-owned subsidiary of the Nigerian National Petroleum Corporation (NNPC), and is engaged in Oil & Gas Exploration and Production activities in the hydrocarbon-rich regions of coastal Nigeria, both onshore and offshore; and more recently, around Equatorial Guinea. Its vision is to be Nigeria's premier E&P company, profitably operating a global Petroleum E&P business using current technology. According to Mrs Madueke, Minister of Petroleum Resources, by 2015, withi its growth plan,

20 Oil Review Africa Issue Five 2012

NPDC would be rubbing shoulders with the Petrobras of this world. Currently it has a reserve base of 240mn barrels and a production capacity of 70,000 bpd. Its operations are centred mainly in the Niger Delta - Edo, Delta, Balyesa and Rivers - and also in the Okono/Okpoho offshore field OML 119. In seeking to attain its vision, MPDC intends to pursue an accelerated exploration and production of underdeveloped proven reserve in all of its blocks through agreed arrangements, and begin aggressive exploration activities in deep offshore blocks won in competitive bidding or assigned to it. Pan Ocean Oil Corp (Nigeria) Ltd Pan Ocean Oil Corporation (Nigeria) Ltd. was incorporated in 1973. Since then, it has been operating as an exploration and production company in a Joint Venture (OML 98) with the NNPC, onshore the northern fringe of the Niger Delta. In 2007, Pan Ocean purchased another block, OPL 275 to be developed as a Production Sharing Contract (PSC). When OPL 275 comes on stream, it will increase the present production volumes. Pan Ocean is a trailblazer in the bid to achieve the gas flare out objective of the Federal Government. Since 1984, Pan Ocean went ahead with its initiative on gas utilisation despite the challenges of an under-developed Nigeria Gas Market. The Ovade-Ogharefe Gas processing plant, said to be the largest in West Africa, earns carbon credits for its operations under the Clean Development Mechanism (CDM) of the Kyoto Protocol. The gas plant is currently the largest carbon emission reduction project in West Africa. Waltersmith Waltersmith Petroman Oil Ltd was incorporated in 1996 as a joint venture between Waltersmith and Associates Ltd, a Nigerian company, and Petroman Oil Ltd of Calgary, Canada, to operate as an oil exploration and production company. In 2001, Walter Smith Petroman Oil Ltd became a wholly

Atlantic Energy Atlantic Energy is a privately owned upstream oil and gas company founded in 2010 by Nigerian and International Exploration and Production (E&P) executives with an extensive track record, marketleading insight and extensive experience in the Nigerian independent E&P sector. Atlantic Energy’s vision is to build one of the leading indigenous Nigerian oil and gas exploration and production companies in targeting 1,000 mmboe reserves and 150,000 boepd production in two countries by end 2015. The corporate organisation has been developed through experience in the Nigerian E&P sector where a small overseas headquarters is utilised to support the financial and technical functions within the main organisation in Nigeria. Brittania-U Brittania-U Nigeria Limited is an indigenous company incorporated on 4th December, 1995 under the laws of the Federal Republic of Nigeria. In a very short period of operation, the company has established subsidiaries and/or sister entities that belong to either the hydrocarbon exploitation chain or provide services to the businesses in the hydrocarbon chain. This has made Brittania-U become more integrated and versatile in the oil & gas industry and allied services.

Integrated Energy Services Oando plc Another leading light in Nigeria’s upstream industry is Oando plc, the country’s biggest indigenous integrated energy player. The company commenced work in the upstream sector but its success has led to deep involvement in energy services and in the downstream and midstream segments, from refining to retailing fuel. It now owns over 500 retail and commercial fuel outlets across Nigeria and other parts of West Africa. Upstream operations remain vital, however. The company’s upstream unit Oando Exploration and Production Ltd recently signed a farm-in agreement with Network Exploration & Production Nigeria (NEPN) for the acquisition of a 40 per cent interest in the Qua Iboe field (OML 13). This

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Nigeria

expansion. “We have worked in Ghana and Gabon and also Togo, but because the Nigerian market is growing so fast, it has slowed our international growth.” The company provides essential pipeline maintenance services to operators, such as cleaning, descaling, inspection, plus commissioning work which includes pressure testing services. On the well services side, its work includes wireline measurement services, wireline logging and completions. It has also established manufacturing facilities. Onuoha admits he is also “positive” local content rules. “It is opening up areas of the market where we were not able to participate before, especially offshore. People are now noticing us.” Naturally, this has impacted growth at the company, with BG Technical effectively doubling in scale in the two years since the new local content rules were introduced.

Transportation services

MPDC intends to begin aggressive exploration activities in deep offshore blocks.

A measure of Oando’s growing international status, it is secondary listing on South Africa’s Johannesburg Stock Exchange field, awarded to NEPN as part of the 2003 marginal field round, is located onshore near the mouth of the Qua Iboe River in Akwa Ibom state, about 2 km from Mobil Producing Nigeria’s Qua Iboe export terminal. The asset is estimated to contain 11.3mn barrels of reserves. Oando’s chief executive Wale Tinubu said the latest acquisition is consistent with the group’s aim of expanding its upstream portfolio with a mix of producing or near term assets and organic growth. “The Qua Iboe field will be the third marginal field with pre-existing proven undeveloped

reserves in Oando’s portfolio,” he said. The company already holds more than a dozen exploration and production assets, both in Nigeria and across West Africa. A measure of the company’s growing international status, it is secondary listing on South Africa’s Johannesburg Stock Exchange, in addition to its Nigerian Stock Exchange presence.

Pipeline & well services: BG Technical Nigerian services provider BG Technical works across two core areas, pipelines and wells, supporting upstream operators both at home and also abroad. After cutting its teeth in the local market, the company has now completed assignments across West Africa, from Ghana to Gabon. And yet, interestingly, BG Technical’s executive director Geoff Onuoha says the strength of the domestic market has held back international

Caverton Helicopters Nigerian transport services firm Caverton Helicopters is growing fast on the back of the nation’s lucrative oil and gas sector. The young company is in the process of upgrading its fleet with more advanced aircraft, receiving support from big international operators such as Shell, one of its main clients. Caverton is purchasing a fleet of six new AW 139 aircraft, partly facilitated by a loan of US$85 million from the oil giant. The fleet expansion will make Caverton the largest operator of the aircraft in sub-Saharan Africa. The company operates mainly from facilities in Lagos, Port Harcourt and Warri. Like other successful Nigerian players it is increasingly active overseas, with one multi-year contract for aerial surveillance work and passenger transfer services on the Chad-Cameroon pipeline. The pipeline carries crude oil from the Doba oil fields in Chad, a landlocked country, to Cameroon via a 1,070 km underground pipeline that runs through three pump stations, a pressure reduction station, and an offshore export terminal. Caverton’s chairman Remi Makunjuola said this project underscored the “increasing confidence in the competence of Nigerian companies.” ■

Brass LNG project to take off in first quarter of 2013 CHAIRMAN OF THE Board of Brass Liquefied Natural Gas, Dr. Jackson Gaius-Obaseki has said that the project would take off on or before the end of the first quarter of 2013. Dr Gaius-Obaseki disclosed this when the Board and management team of BLNG visited Governor Seriake Dickson recently. According to him, the final investment decision (FID) will be taken soon and he called on all stakeholders to collaborate effectively to achieve this target. In his presentation, the Managing Director of BLNG, Mr. Lorenzo Di Lorenzo said contracts for the construction of Gas Trains Engineering and Procurement, Onshore and Offshore works including loading facilities have been awarded to Bechtel. The Managing Director noted that the project, when operational, will not only provide sustainable development for local communities in the Niger Delta, but also complement Federal Government’s gas flare-down policy and buy into global Kyoto Protocol Objectives. According to him, BLNG has so far trained over 125 technicians at

22 Oil Review Africa Issue Five 2012

the Petroleum Training Institute, Effurun, Warri in Delta State as well as built a community information centre and a health facility at Twon-Brass as part of its corporate social responsibility. To demonstrate its commitment to the project, Governor Dickson noted that his administration is prioritising the Nembe-Brass road and the development of a deep seaport in the state. According to him, the design of the road will make provision for the construction of a railway on the long term to connect the state to commercial centres such as Onitsha. Commending the company for its training programmes, Hon. Dickson urged the BLNG to complement his administration’s efforts at giving specialised training to more youths in areas such as underwater welding with a view to making them relevant for the project. The governor acknowledged BLNG’s recognition of the relevance of the Nigerian Content Development and Monitoring Board, pointing out that the activities of the board could lead to a multiplier effect that would actually accommodate grievances that might be expressed by some of the host communities.

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Nigeria

The Nigerian draft Petroleum Industry Bill (PIB) has been hailed as a landmark opportunity to introduce a new era of reform to Nigeria’s oil and gas industry. Stephen Williams reports.

Explaining

the PIB T

HE NIGERIAN DRAFT Petroleum Industry Bill 2012 was submitted to the National Assembly on 19th July. Less than a fortnight later, Nigeria’s Minister of Petroleum, Deizani Alison-Madueke presented at the New World Nigeria summit. Many were there to hear her discuss the long awaited bill which, when passed into law, will be the overriding guide for the oil and gas industry in Africa’s largest oil producer. The Petroleum Industry Bill (PIB) has been hailed as a landmark opportunity to introduce a new era of reform to Nigeria’s oil and gas industry that will better exploit the country’s vast potential, restore transparency and facilitate a thriving industry and overall economy. It will, if passed by the legislature, replace an aggregation of some 16 existing petroleum industry laws that have governed the sector for a half-century of oil and gas operations in the country. The mammoth 223-page PIB seeks to reform, deregulate and liberalise the oil and gas sector. That much was made clear by Nigeria’s Minister of Petroleum, Deizani Alison-Madueke during her presentation to the New World Nigeria investment summit, held at the luxury Dorchester Hotel in London in early August. The thee-day New World Nigeria event was sponsored by Nigeria’s Bank of Industry and the Nigeria Olympic Committee, and expertly organised by Brand Communications. As well as the Minister of Petroleum, it drew together a number of high-level Federal government officials and State governors. Discussing the PIB, Alison-Madueke told delegates: “This bill provides for a dynamic but prudent fiscal policy framework across the value chain which provides the incentives for sustained investments and productivity whilst delivering best returns to Nigeria.”

The mammoth 223-page PIB seeks to reform, deregulate and liberalise the oil and gas sector. New national oil company The PIB will unbundle the Nigeria National Petroleum Corporation and create a new national oil company (NOC) that will promote indigenous operational capacity development. Almost as importantly, the deregulation will allow the NOC and its joint ventures to list on the Nigeria Stock

24 Oil Review Africa Issue Five 2012

Deizani Alison-Madueke recently presented at the New World Nigeria summit.

Exchange’s (NSE), impacting the whole of Nigeria’s finance industry. The NOC will be permitted to float up to 30 per cent of its shares within six years and the Nigerian Gas Company (NGC) 48 per cent of its shares within the same period. It is the fiscal and regulatory reforms that have created so much debate and delay to the PIB’s introduction. Legislators have been working on the document for a number of years – and it did not help when several versions of the bill with various amendments were widely circulated. Nevertheless, Alison-Madueke was able to confirm that the fiscal regime (for both royalties and tax) will, under the PIB, be predicated on production as opposed to terrain and investment respectively. The Company Income Tax Acts’ rate is 30 per cent regardless of geographical location, while the Nigeria Hydrocarbon Tax (NHT) and Production Bonus will be based on production as opposed to investment. “It is fair to both small and large producers,” Alison-Madueke says. The proposed NHT rate is 50 per cent in the case of onshore/swamp/shallow offshore and 25 per cent for deepwater operations. Two distinct regulatory institutions are being proposed by the PIB with both an Upstream Petroleum Inspectorate and Downstream Petroleum Regulatory Agency.

Dissenters and critics Perhaps it is inevitable that with such a complex piece of legislation concerning a key economic

“The biggest beneficiaries of this bill, by any yardstick, will be the indigenous companies, the local companies.” sector there should be dissenters and critics. These tend to focus on the end-of-year deadline for an end to gas flaring as being too ambitious; that too much power will reside with the President and Minister to grant, revoke and allocate licences; and the proposed regulatory institutions not being truly independent but under the supervision of the Minister. A very unscientific poll of the New World Nigeria delegates found broad agreement with Alison-Madueke’s proposals. When asked if anything had been learnt from the minister’s presentation, one senior banking figure told Oil Review Africa: “Yes and no. It was nice to actually hear the oil ministry articulate some of the things behind the PIB. I’ve never been that worried about the content, because I actually think Nigeria is still the benchmark against which the other African oil producing countries operate. That’s a very important point. My only worry is that the length of time that it’s taking to write the bill! The biggest beneficiaries of this bill, by any yardstick, will be the indigenous companies, the local companies.” ■

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Nigeria

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Shell Nigeria sells OML stake to Elcrest

Nigeria pledges support for local oil firms

SHELL PETROLEUM DEVELOPMENT Company of Nigeria (SPDC), a subsidiary of Royal Dutch Shell (Shell), has completed the US$102mn sale of its 30 per cent interest in Oil Mining Lease (OML) 40 in the Niger Delta to Elcrest Exploration and Production Nigeria The divestment is part of Shell's strategy of refocusing its onshore interests in Nigeria and is also in line with the Federal Government of Nigeria's aim of developing Nigerian companies in the country's upstream oil and gas business. Including this license, six onshore lease assignments have been completed by SPDC in Nigeria since 2010. "These divestments mark another step in the strategy to re-focus the SPDC portfolio,” said Mutiu Sunmonu, the company’s country chairman in Nigeria. “SPDC is positioned well for investment and growth opportunities in all areas, including domestic gas, which will be delivered with the support of our government, partners and the people of Nigeria." Shell, which has been in Nigeria for more than 50 years, has stated that it remains committed to keeping a long-term onshore and offshore presence. Elcrest Exploration and Production Nigeria Limited is a majority Nigerianowned consortium consisting of Starcrest Nigeria Energy Limited and Eland Oil and Gas Limited. OML 40 covers an area of nearly 500 sq km and includes the Opuama, Abiala and Adagbassa Creek fields and related facilities. Operations had been suspended since 2006 because of militant activity. Total E&P Nigeria Ltd (10 per cent) and Nigerian Agip Oil Company Ltd (five per cent) have also assigned their interests in the lease, effectively giving Elcrest a 45 per cent interest.

NIGERIA’S PETROLEUM MINISTER, Mrs Diezani Alison-Madueke, has reiterated the government’s support for local oil companies in all aspects of the oil and gas sector, saying plans were in the works by the government to raise funds in support of genuine local investors wishing to exploit opportunities in the sector. She spoke at the inauguration of Orient Petroleum Plc’s Anambra River Production Facility in Aguleri-Otu in Anambra State, the first oil production from an inland basin in Nigeria. According to Alison-Madueke, President Goodluck Jonathan has directed both the Ministry of Petroleum and the Ministry of Finance to set up an inter-ministerial committee to fashion out modalities for raising financial support for indigenous oil companies like Orient who are ready to invest not only in production but also in refining to add value to the crude oil and gas locally before exporting in order to generate employment for the youth and more money for the country. Maintaining that the significance of the event was not just in the discovery and production of oil from an inland basin, she said the good thing was that the achievement was by an indigenous company. “This shows the way we want to go in the industry; we want to encourage more indigenous oil companies to emulate Orient Petroleum Resources in investing not just in production but also in refining. “We are working with the Ministry of Finance to set up an inter-ministerial committee to work out ways to give financial support to indigenous companies to bring in modular refineries,” she stated.

NNPC, NCDMB to integrate Nigerian Content into refineries THE NIGERIAN CONTENT Development and Monitoring Board (NCDMB) and the Nigerian National Petroleum Corporation (NNPC) have resolved to integrate Nigerian Content into downstream operations of the oil and gas industry, including the Turn-Around Maintenance (TAM) planned for the four refineries within the next two years. This was part of the strategic agreement reached between the top management of NNPC led by the Group Executive Director, in charge of Refineries and Petrochemicals, Mr. Anthony Ogbuigwe and the Executive Secretary of NCDMB, Mr. Ernest Nwapa in Yenagoa. Nwapa said appreciable progress had been achieved in the upstream subsector of the industry where his agency had set up an effective process for interfacing with operators and service companies to positively influence their activities, pointing out that a similar model needed to be worked out for the downstream. To achieve this, Nwapa said: "Institutional synergies must be enhanced at strategic levels, where the NCDMB would be able to obtain the subsector's long term plans, so as to identify opportunities, devise programmes and interface points that will best grow Nigerian Content in the downstream without disrupting operations". This, he said, would "engender job creation, spur local equipment manufacturing, retain spend, transfer technology and deliver other benefits of implementation".

26 Oil Review Africa Issue Five 2012

Private sector gas project A MULTI-BILLION naira gas project that will boost power generation in Nigeria by 1,000 MW, could be ready for commissioning by the end of the year. The project is being executed by a consortium of private investors which include Frontier Oil Limited, Gulf Energy Nigeria Limited and Septa Energy Nigeria Limited, in the Esit Eket Local Government Area of Akwa Ibom. Briefing the Akwa Ibom Governor, Chief Godswill Akpabio, in Uyo, the Chairman of Frontier Oil Limited, Chief Odoliyi Lolomari, said that the plant had the capacity to produce two million cubic feet of gas. Lolomari, who led management teams of the three companies, said that the 62-km gas pipeline from Esit-Eket area to Ibom Power Plant and Aluminium Smelter Company of Nigeria, ALSCON, all in Ikot Abasi Local Government Area, would also be ready. The chairman described the plant as an important project and a major milestone in the life of Frontier Oil Limited. Responding, Akpabio thanked the companies for the successful completion of the project. He said that the project was strategic to the transformation agenda of President Goodluck Jonathan in the power sector. “This is a practicable step by the private sector to look into gas flaring; Akwa Ibom is proud to partner with you on this project. “We will continue to encourage you. We will encourage every private industry, at least one in every local government area, to create employment opportunities for our children. “We have set aside funds to encourage the private sector to establish the industries. The oil and gas industry should also invest in other sectors, particularly the agro-allied industry.” The governor lauded the cordial relationship between the companies and the host communities and urged them to create employment opportunities for indigenes of the host communities. The MD of Frontier Oil Ltd, Mr Dada Thomas, said that the company had made substantial progress in the ongoing Uquo Field development and construction of the gas plant. He requested President Goodluck Jonathan, through Akpabio, as well as notable players in the power and petroleum sector, to witness the inauguration of the projects.

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Making waves in the services sector Alduco Energy is a Nigerian company that has being making waves in the oil & gas industry in the Gulf of Guinea. ALDUCO ENERGY WAS set up to help companies meet their objectives through assisting them to ensure the integrity of their facilities. It provides asset integrity management services for new and mature facility owners. Its core activities include Non-Destructive Testing (NDT), Risk-Based Inspection (RBI), corrosion control and Cathodic Protection.

Protecting oil and gas facilities Oil & Gas infrastructure locally, regionally and globally has one thing in common, which is corrosion problems. Managing corrosion is one of the key challenges facing operators in their drive to maintain the integrity of their assets. Stringent regulatory and company requirements are making companies ensure the integrity of their infrastructure by implementing asset integrity management solutions, to make sure their facilities are in a safe operating condition, as failure to do so could result in facilities whose integrity are compromised, the result could be costly unplanned shut downs, accidents, major financial loss, environmental damage and even potential fatalities with serious legal consequences. The challenge faced by asset owners especially those that operate offshore is the complexity and high cost of replacing subsea corrosion control systems, especially depleted Cathodic Protection (CP) systems, ie, anodes. The oil & gas industry is constantly engaging the services of specialist corrosion control companies like Alduco Energy to assist them to mitigate their corrosion problems. From its two bases in Nigeria and Equatorial Guinea, Alduco Energy has being providing the worldâ&#x20AC;&#x2122;s most innovative and cost effective Cathodic Protection (CP) solutions, to assist operators in extending and maintaining the integrity of their

28 Oil Review Africa Issue Five 2012

assets including platforms, FPSOs, pipelines and other subsea infrastructure. Alduco Energy has carried out numerous retrofits of depleted CP systems that were no longer protecting the facilities they were intended to protect, due to damage or because they had reached the end of their design life. This has been done in record time, with minimum disruption to the operations of the oil & gas companies, and with cost savings in some cases as much as 80 per cent. Alduco Energyâ&#x20AC;&#x2122;s solutions have helped to extend the life, by between five to 20 years, of many oil & gas facilities in the Gulf of Guinea. Alduco Energyâ&#x20AC;&#x2122;s client list includes ExxonMobil, Marathon Oil, Hess, SBM Offshore, EGLNG, Perenco, Noble Energy, Atlantic Methanol Production Co, Globestar, Cakasa, and Consolidated Contractors Company, among others. In recognition for its work in the oil & gas industry in the Gulf of Guinea, the company was given the prestigious award of National Company of the Year 2012 by the international Oil & Gas publication, The Oil & Gas Year (TOGY). The award was presented to the Managing Director of Alduco Energy, Alfredo Jones, by His Excellency the Minister of Mines, Energy & Industry of Equatorial Guinea, Gabriel Mbaga Obiang Lima. Alduco Energy takes its local content obligations very seriously, and to enable it to be at the forefront of the latest Asset Integrity Management methods and technology, it has formed a joint venture (J/V) with Deepwater Corrosion Inc, a world leader in the provision of life extension solutions for offshore oil & gas facilities. Deepwater Corrosion Inc engineers from Houston work alongside Alduco engineers in Nigeria, enabling technology transfer and building the capacity of the team, which in turn has permitted the company to offer its world class services to its clientele in the Gulf of Guinea, competing with well established international companies and in some cases outperforming them.

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Integrating Ghanaians into all aspects of the oil and gas industry will be of maximum benefit to the country. Jon Offei-Ansah reports.

Local capability in

all aspects T

HE GHANA PETROLEUM Commission (GPC), the government body set up to supervise the oil sector, is stepping up efforts to enforce the government’s local content policy in the oil and gas industry. Kwabena Donkor, the managing director of the commission which also awards licences and oversees legislation – has issued a warning to foreign oil companies in the country that they will soon be obliged to comply strictly with rules concerning work permits. Before arriving in the country, expatriates will have to submit resumés, a clean police record and other documents to the GPC for scrutiny and approval. Before Donkor’s announcement, most oil companies simply submitted paperwork to the state-owned oil company, the Ghana National Petroleum Corporation (GNPC), without waiting for its agreement to bring in workers from abroad. The authorities agreed to that simple practice to circumvent official red tape. In addition to Donkor’s warning, the GPC has sent written inquiries to oil companies active in Ghana about their plans to boost the number of locals in their workforce. According to the GPC, the companies will also impose a minimum requirement of Ghanaian workers on offshore oil rigs.

The policy’s stipulations Local content, according to the GNPC, is the level of use of Ghanaian local expertise, goods and services, people, businesses and financing in oil and gas activities. The local content policy stipulates that all regulatory authorities, operators, contractors, sub-contractors and any other entities involved in any project, operations, activity or transaction in the Ghanaian oil and gas industry shall consider local content as an important element in their project development and management philosophy for project execution. The policy seeks to give first consideration to Ghanaian independent operators in the award of oil blocks, oil field licenses, oil lifting licences and in all projects for which contract is to be awarded in the Ghanaian oil and gas industry. An important feature of this policy stipulates that, where bids are being evaluated, and where bids are otherwise equal, the bid containing the highest level of Ghanaian content shall be selected. Such a provision sounds great for local Ghanaian operators and businesses and will in effect place Ghanaians at the forefront of the nation’s oil business in a relatively shorter period. In the case of non-Ghanaian ownership and operations, the entity must provide for the

30 Oil Review Africa Issue Five 2012

The issue of local participation in the country’s nascent oil industry is of grave importance to the government.

Such a provision will in effect place Ghanaians at the forefront of the nation’s oil business in a relatively shorter period. participation of a citizen of Ghana in an interest of at least five per cent in the exploration and production activities under petroleum licenses. Another important feature of the policy is that a fund, Oil and Gas Business Development and Local Content Fund, is to be established to support local capability development aspects of the local content framework. The fund will be used primarily for education, training and research and development in oil and gas. Sources of the fund will include contribution from licensed operators, oil and gas revenue, levies, grants and other support from Ghana’s development partners. The ministry of energy will oversee the disbursement of the fund. This is undoubtedly fitting for a developing nation like Ghana but it remains to be seen how effective the administration of this fund will be. In general, the move by government is expected to obligate operators to attach significant importance to local content and to ensure that as many benefits as possible are retained in the local economy by indigenes.

Developing local capability The issue of local participation in the country’s nascent oil industry is of grave importance to the government. Integrating Ghanaians into all aspects of the oil and gas industry will be of maximum benefit to the country. ‘It is our wish that within a decade, the country will be able to achieve at least 90 per cent local content and local participation in the oil and gas industry,’ Energy Minister Joe Oteng said earlier this year. Oteng told a trades union group in Accra recently that plans were far advanced to prepare a schedule by which the strategy would be rolled out in advancing the stake of Ghanaians in the industry as stipulated in the policy framework document – the Local Content and Local Participation in Petroleum-related Activities - which was approved by the cabinet earlier this year. ‘We hope to see the development of local capability in all aspects of the oil and gas value chain through education, skills and expertise development, transfer of technology and know-how and active research and development activities,’ Oteng said.

Scholarship packages available In order to meet the high expertise and skills needed in the industry, building the capacity of the local people had become paramount and the government, in collaboration with operating companies, had arranged scholarship packages for Ghanaians to pursue further studies in various fields as part of the nation’s capacity-building and local

S05 ORA 5 2012 Ghana_Layout 1 02/10/2012 16:46 Page 31

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Ghana

oil field, Tullow Oil, says local content build-up is at the heart of its operations because of the commercial advantages. According to Tullow communications manager Gayheart Mensah, local capacity building and capability development helps to ease access to local raw materials for the company whilst creating shared prosperity in the country.

A business imperative

Local content is seen as a business imperative.

Local content build-up is at the heart of Tullow’s operations. content efforts to achieve desired levels of expertise and know-how over time. The government is also rolling out an Oil and Gas Capacity Building Project which would focus on building capacity to manage Ghana’s oil resources. ‘In addition, the government is collaborating with

the upstream oil companies working in Ghana to provide overseas training to Ghanaians as part of the local content provisions in the respective oil and gas contracts,’ Oteng said. Through such strategic oil and gasdriven industrialisation programmes, the government believes the manufacturing sector will receive a significant boost, which will in turn contribute to a rapid and sustainable growth of the economy. The operator of the country’s major Jubilee

‘We see local content as a business imperative. It makes commercial sense. If you are able to develop the local capacity of communities within which you operate, it helps you to source your raw materials and other services required locally,’ he said. Mensah added that Tullow has devoted time and resources to invest in training of local suppliers across the country to service the budding oil and gas industry. ‘We have set up an entire department solely focusing on local content and the purpose is to come up with measures and interventions that will help us to focus on developing local capacity in support of the oil and gas industry,’ Mensah told the Ghana News Agency (GNA) recently. A Tullow Group Scholarship Scheme was recently launched in conjunction with the British Council to help develop local skills and expertise in the oil industry by supporting post-graduate degrees, technical training and vocational studies. ■

Ghana’s gas ready by January now just a

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32 Oil Review Africa Issue Five 2012

GHANA IS EXPECTED to produce its first gas from the Atuabo Gas processing Plant by January 2013 after the completion of the first phase of the project by December 2012. The first phase involves the construction and installation of equipment. Victor Kofi Sunu-Attah, a Project Development Manager from the Ghana National Gas Company (GNGC), stated this during a recent presentation in Accra. The initial projected feed gas rate from Atuabo will be 150 mmscfd. The project, being undertaken by GNGC and its Chinese contractors Sinopec, includes the construction of associated infrastructure at Atuabo and surrounding communities in the Western Region. The facility will process gas from the Jubilee field into clean fuels and feedstock for the domestic and export markets while promoting the development of the country’s petrochemical industries to eliminate the flaring of gas. Mr. Sunu-Attah indicated that “GNGC has been given its marching orders by the Ministry of Energy to give the first gas to the Volta River Authority (VRA) by February of the same year (2013).” He explained that there has to be a pre-commissioning and commissioning of the pipeline. Pre-commissioning is a series of processes carried out on the pipeline before the final product is introduced while commissioning means introducing the gas into the pipeline. Mr. Sunu-Attah noted that the first phase of the project includes the “completion of storage facilities and an offshore buoy for export of liquefied petroleum gas (LPG) and condensate at Domunli in the Western Region. He said the medium-long term development and expansion phase of the project includes a network of pipelines from the FPSO facility and other reserves from the basin to the gas processing plant. In the near future, he said GNGC will float shares on the stock market to ensure “wider Ghanaian participation in petroleum activities and economic and social benefits from broadening ownership in the country’s natural resources.

S06 ORA 5 2012 South Africa_Layout 1 02/10/2012 17:43 Page 33

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S06 ORA 5 2012 South Africa_Layout 1 02/10/2012 17:43 Page 34

South Africa

Lack of supply has hampered development of the natural gas industry – until now.

Mozambique’s gas fields - a boon for Mossel Bay’s

gas-to-liquids refinery ? R

ECENT NEWS ON the oil and gas sector in sub-Saharan Africa has been dominated by discoveries of vast resources in several countries including Ghana, Uganda, Tanzania and Mozambique. Tanzania tripled its estimated gas reserves in June after offshore finds by Norway's Statoil, ExxonMobil and Britain's BG Group and is studying various models for managing revenues from gas production, including a sovereign wealth fund to facilitate the use of natural gas revenues and to speed up development. East Africa's second-biggest economy, Tanzania, joins other African countries like Nigeria and Ghana who are also moving towards state-owned investment funds for revenues generated from the energy sector. It is also working on a new national gas policy, gas utilisation plan and legislation to regulate the industry. The country’s recoverable onshore and offshore gas reserves are estimated at 28.9 tcf. Gas exploration has escalated since 2010 and there are now about 18 companies involved. According to the World Bank, Tanzania could see an increase in revenue of up to US$3bn a year from gas exports. Other advantages include boosted power generation with some 350 MW of electricity in the national power grid currently coming from natural gas. The target is 3,500MW by 2015. In Kenya, Tullow Oil said it planned to accelerate drilling after making the East African state's first discovery earlier this year. Alongside Africa Oil, Tullow is deploying two rigs in Kenya and one in Ethiopia this year to confirm reserves after the Ngamia-1 well discovered more than US$100m of light oil. Chief financial officer, Ian Springett, commented in July that Kenya has the potential to exceed Uganda, where Tullow plans to invest more than US$10bn with its partners to access an estimated 2.5-bn barrels of oil. The British company's Kenyan exploration acreage may hold as much as 10-bn barrels. Tullow's first-half output in Kenya averaged 77,400 barrels with production expected to exceed 90,000 bpd by the end of the year. Tullow said that a potential export pipeline from Uganda could cross Kenya to bring oil to a port on the Indian Ocean coast. In Ghana, it has applied new production methods intended to almost double output to 120,000 bpd by next year. Large natural gas discoveries off the coast of Mozambique have also put that country in the spotlight. According to Bain and Company, “Mozambique is in place to become one of the

34 Oil Review Africa Issue Five 2012

PetroSA's Project Ikhwezi.

Mozambique's proximity means that the gas fields could be a boon for its gas-to-liquids refinery in Mossel Bay. world’s largest exporters of LNG, and large international oil companies are the obvious players as they have the technical know-how and scale to develop, operate and maintain massive gas fields in deep waters. Anadarko Petroleum estimates its reserves off northern Mozambique at 1.4 tcm and Eni recently announced that a new discovery at its Mamba field would take gas in place to about 1.95 bcm.

Sasol initiatives in Mozambique South African multinational Sasol says its initiatives in Mozambique include the expanded natural gas central processing facility in Temane. It also plans to develop additional gas-fired electricity generation in Mozambique, in partnership with the country's state-owned power utility, Electricidade de Moçambique. For South Africa’s national oil company, PetroSA, Mozambique's proximity means that the gas fields could be a boon for its gas-to-liquids refinery in Mossel Bay, which faces declining supplies. The gas revolution in Mozambique is expected to give PetroSA supply options for the Mossel Bay plant, its main revenue driver. Currently, PetroSA's hopes for feedstock solutions hinge on the production of gas from its South African offshore gas field as part of Project Ikhwezi, which entails producing gas from a new

field about 80km off the coast. The first gas is scheduled to flow from this field next year with production expected to continue for about six years. PetroSA said further development of other gas prospects near the field could help to sustain the life of the Mossel Bay refinery until 2025. "Project Ikhwezi creates a critical opportunity for sustaining the operations of our gas-to-liquids refinery. It ensures that we continue to play a vital role in the South African petrochemicals market. Most importantly, PetroSA will continue to be a source of much-needed employment in the southern Cape," PetroSA CEO Nosizwe Nokwe-Macamo said. The company said the drilling operation for the five Project Ikhwezi wells was scheduled to start in November and should be completed by the second quarter of 2015. It will take approximately six months to complete each of the five wells, with work on installation of subsea pipelines expected to start in the last quarter of this year. PetroSA has also entered into a co-operation agreement with its Mozambique counterpart, PetroMoc, and wants to jointly develop and operate a gas-to-liquids refinery in Mozambique.

PetroSA aims to be downstream player The relationship with PetroMoc could help PetroSA achieve its aim to be a player in the downstream sector as part of its strategy to become a fully integrated, commercially competitive national oil company supplying at least 25 per cent of SA's liquid fuel needs by 2020. Its acquisition in May of BP's inland petroleum storage facilities is part of the plan to enter the downstream market. PetroSA is planning to build a large crude oil refinery, the cost and size of which will be

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South Africa

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determined by the joint study agreement it signed with Chinese oil and gas group Sinopec. The costs of the refinery, also known as Project Mthombo, have previously been estimated at $9bn, with a capacity of 360 000 barrels a day. In August PetroSA announced an agreement with Anadarko Petroleum for the exploration of blocks off the South African coast. Everton September, Petro SA’s vice president for new ventures said: “This deal represents a significant landmark in the development of the oil and gas industry in South Africa. Anadarko has an excellent track record in successful exploration and production.” Although South Africa does not have significant proven gas reserves, the potential for reserves to be found remains a possibility, according to a report by PwC. Chris Bredenhann, PwC Southern Africa Energy Leader, said that while the introduction of more natural gas into the energy mix in South Africa could lead to a reduction in greenhouse gas emissions, the dominance and relatively low cost of coal was preventing natural gas from taking a larger share. While the debate about hydraulic fracturing for shale gas in the Karoo continues to grab the spotlight amid environmental concerns about the ecologically sensitive and arid region, PwC said the broader discourse about the role of gas in the

energy mix needed to continue. Based on the extent of actual and proposed onand offshore exploration activity, the number of license applications submitted to the gas regulator, and the specific energy needs of the country, PwC found that there is significant interest in exploring for and developing a natural gas industry in South Africa. Barriers to the development of the industry could be overcome by importing gas, although the country would then be exposed to commodity and exchange rate risks. Although Government had indicated support for increasing the share of natural gas in the energy mix, another barrier was the lack of a credible industry development plan. Also, in terms of South Africa law, mineral resources belong to the state and not the landowner. Bredenhann said this created an incentive for landowners to allow for exploration and production. For a natural gas market to develop in South Africa, certainty of supply is required. There is significant, although unproven potential for indigenous natural gas reserves, mostly in the form of shale gas in the Karoo, but the impact of coal bed methane gas should also not be underestimated. In addition, the discoveries in Mozambique and Tanzania could provide additional gas resources. The report states that demand for natural gas

The Coega Development Zone.

will be influenced by carbon constraints, as it becomes increasingly difficult to obtain funding for coal-fired power stations due to the high levels of greenhouse gas emissions. “This will more than likely lead to increased demand for natural gas and renewable energy,” said Bredenhann. The immaturity of the natural gas industry in South Africa means there’s not much competition. Bredenhann says this can be attributed to the lack of indigenous supply and the dominant position of Sasol in the local market. This position is protected by the Gas Act, which gives Sasol exclusivity for the importation of natural gas from Mozambique until 2014. Given the significant investment required to build pipelines and processing facilities, another factor affecting competition is the capital intensity of the industry. ■

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36 Oil Review Africa Issue Five 2012

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Libya targets oil production increases to 1.8mn bpd in 2013

SOU TH

GENCY FOR N A PR CA RI

OF PETRO ION LE OT UM M O

earlier in September, is operating at 180,000 bpd, Berruein said. Gas production is still at around two-thirds pre-crisis volumes because of technical problems with some subsea wells that still need to be brought back, he said, adding that he expected gas exports to Italy to be restored to their previous level by the end of the year. Having restored oil production to pre-crisis levels, Libya is now looking ahead to a stepped-up exploration campaign in an effort to boost both its oil and gas reserves, expanding and upgrading its oil refineries as well as developing its shale gas reserves. Berruein said the foreign oil companies that were awarded exploration acreage in 2006 and 2007 are due to resume their activities in early 2013. He said BP, which won one a major exploration deal during the Qadhafi era, had committed to drilling five wells in deep offshore waters, hopefully before the end of 2014, assuming the right drillship is secured. Most of the seismic surveys have been completed and companies that have made discoveries offshore will have to return to Libya to assess their discovery. Total's managing director in Tripoli, Bernard Avignon, said that the French major, with partners Wintershall of Germany and NOC, plans to begin offshore exploration next month. Libya has had four bidding rounds since December 2004, shortly after US and UN Security Council sanctions that had held back Libya's oil and gas sectors for several years were lifted. Future bidding rounds will have to be tweaked because Libya needs state of the art exploration for the less prospected areas and for the deep offshore. "We are not going to offer any concessions until a proper government is in place," Berruein said.

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IO ORAT N AND PL EX EX P

Petroleum Agency SA encourages investment in the oil and gas sector by assessing South Africa's oil and gas resources, and presenting these opportunities for exploration to oil and gas exploration and production companies. Compliance with all applicable legislation in place to protect the environment is very important, and rights cannot be granted without an approved Environmental Management Plan. Explorers must prove financial and technical ability to meet their commitments in safe-guarding and rehabilitation of the environment. Preparation of Environmental Management Plans requires public consultation and a clear demonstration that valid concerns will be addressed.

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Oil Review Africa Issue Five 2012 37

Libya

LIBYA IS CURRENTLY producing an average 1.6mn bpd and expects to increase output by 30,000-40,000 bpd by early 2013 once repairs to one of the pipelines in eastern Libya are completed, according to Nuri Berruein, National Oil Company Chairman. "We have held back production from some oil fields in order to preserve wellhead integrity so that we do not cause any damage," Berruein said, adding that a pipeline being built in partnership with Wintershall of Germany would be completed "in record time," allowing oil production to resume at higher levels from three or four fields in the Sirte Basin that is currently being held back. NOC and Wintershall agreed in June to build a new pipeline to replace a corroded pipeline that links a cluster of fields in the eastern Sirte province, the first major infrastructure project to be undertaken since the end of the rebellion that ousted Moammar Gaddafi in October last year. When completed, export capacity is expected to rise by 100,000 bpd. Foreign oil companies shut down production and evacuated staff from Libya at the start of the anti-Gaddafi rebellion in early 2011, leading to a total shutdown of production in the OPEC member state. Libya was producing an estimated 1.6-1.7mn bpd before the crisis and has been able to restore capacity to its previous levels relatively quickly since the end of the civil war. Berruein said the target was to produce 1.8mn bpd by 2013 and reiterated the target of two mn bpd by 2015, which Oil Minister Abdulrahman Benyezza has said remained the target under an existing five-year plan. Oil exports are averaging 1.1-1.2mn bpd, slightly below earlier estimates, as all Libyan refineries have resumed full operations. The 220,000 bpd Ras Lanuf refinery, which resumed normal operations

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Libya

New oil exploitation joint venture PT MEDCO ENERGI Internasional (MEDCO), a publicly listed oil and gas company in Indonesia, has announced that it will be launching a joint operation company in Libya. This will be initiated in October and it will be overseeing the development project of its oil field in the country. The to-be developed oil fields are found in area 47 which received the commercial approval of the Libyan government in December. 18 oil wells have been discovered in the area and they will be exploited by Medco Energi Internasional and the Libyan Investment Authority (LIA). The stakes of the joint operating company will be divided between three institutions; namely the Libyan government, the Libyan Investment Authority and Medco Energi Internasional with 50 per cent of the stakes accorded to the government and the remainder will be shared among the other two respectively. Medco president director, Lukman Mahfoedz, said the joint venture will cost US$800mn. Medco will invest US$200mn in the project, funded by internal cash and bond proceeds. He added that the project has been in the preliminary engineering stage and it will produce 50,000 bopd. Production is expected to begin in 2015. The project, according to him, was planned during the reign of Ghadaffi but the outbreak of the political conflict which late uprooted him delayed it.

Medco Energi is the first Indonesian company operating in the oil & gas exploration and production business listed on the Jakarta Stock Exchange since 1994. And it is trying to stand out at the international stage as it focuses on oil and gas, power generation and renewable fuels. Less then two weeks after the ruthless assassination of US ambassador in Libya, this new oil exploitation is interpreted as a positive signal by Libyan authorities, who were fearing disinvestment.

Illustrating OMV programmes to develop local content in North Africa THE CHANGE IN landscape initiated by the Arab Spring has provided several opportunities and challenges for international oil companies (IOCs) that operate in North Africa. OMV Senior Vice President Dr. David Latin recently spoke to The Energy Exchange outlining these challenges as well as the steps taken to build a sustainable oil and gas industry in the North African region. Prior to the war, oil in Libya accounted for 70 per cent of the country’s GDP, 95 per cent of exports and nearly 90 per cent of government revenue, estimates the International Monetary Fund, placing significant stress on OMV and other IOCs. Dr. Latin said that the industry provides

significant value to the countries they operate in, in terms of jobs, revenues, infrastructure and community relation work. With the political environment still evolving as newly appointed officials take office, Dr. Latin stated that rapid decision making is one of the key challenges faced by OMV in the midst of all the ambiguity. In addition, security has to be managed carefully, particularly in Libya and in Tunisia. Libya, the world’s ninth largest oil-producing country with more than 47bn barrels of oil, holds the largest oil reserves in Africa. This oil-rich nation is ideal for IOCs to thrive in; however the current lack of capability building is a challenge as it constrains growth. as well as the implementation of

multi-billion dollar projects. Dr. Latin said: “We want to build local capability and to utilise local content and contracts wherever we are able, but we also want to be able to execute activities to very high standards in a relatively short period of time.” In an effort to maximise local content and retain industry knowledge in North Africa, OMV is currently running specific development programmes. Around 10 per cent of the organisation’s current global production comes from Libya, where they remain a committed partner with plans to grow their business over the next five years. In addition, OMV is also actively evaluating opportunities in other North African countries.

Mabruk Oil operations' VSAT network MABRUK OIL OPERATIONS is one of the oil companies operating on behalf of National Oil Corporation (NOC) and Total E&P. The company has three main operational sites in Libya with its main office in Tripoli. The Mabruk Field is an onshore field located about 170 km south of Sirt. The Al-Jurf field is an offshore field situation close to the Tunisian border, 1,200 km off the coast and 150 km from Tripoli. A fixed drilling and production platform (BD1) in a water depth of 87 m is linked to an FPSO in 83 m of water via 10" sea line of about 3 km distance. The production here reached maximum capacity of 40,000 bopd in less than a year from production start. The company needed to have a reliable and high performance network for data and voice applications, critical for the company business. The VSAT network implemented by the Digital Group connects three sites, the HQ in Dal-Elmad Complex in Tripoli (Mabruk's headquarters), Al-Jurf (BD-1 and FPSO) and Mabruk Field. The satellite used is T 11N (Telesat) located at 37.5° west on Ku-band this satellite has been in service since 2009 and is the preferred choice

38 Oil Review Africa Issue Five 2012

for VSAT and IP solutions. Because this network will be used for data and voice traffic, a reliable connection and quality of service (QoS) is needed, so SCPC (single channel per carrier) technology was used. It is a reliable approach that can guarantee QoS in terms of data transmission rates and voice quality, albeit at higher running costs because the satellite capacity is not shared. Internet service has also been provided to Al-Jurf field (BD-1 and FPSO) on the same equipment, where the uplink is used on the same carrier, but the downlink is used on another carrier. The service is for international internet backbone connectivity between the European internet backbone and customer facilities via the hub through a single satellite hop. The total bandwidth for this network is 10Mbps, where the inbound for each remote site is 2.5Mbps and the outbound is 5Mbps. For each remote site there are 20 voice channels working via the VSAT system and the quality of the voice is perfect.

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Geology

S07 ORA 5 2012 Geology_Layout 1 02/10/2012 17:46 Page 40

BG plans more Kenyan seismic

Major 3D seismic survey in South Africa

BG GROUP IS planning a new 3D seismic survey over the L10A and L10B licence areas, off Kenya, after shoots carried out earlier this year yielded promising results. The British company will carry out a 2280 sq-km shoot over the western portion of the licence areas, covering the cluster of large Miocene reefs and the large Crombec lead. BG completed both 2D and 3D seismic surveys over the licence areas earlier this year, with joint venture partner Pancontinental saying that, while processing and interpretation was still ongoing, preliminary results had been “very encouraging”. It noted a cluster of more than 10 potential Miocene reefs had been identified from the seismic surveys, in water depths of about 500 m and within 50 km of the port of Mombasa. It was also through these surveys that the large Crombec lead was identified, a large anticline in the western portion of the licence areas which has apparent four-way dip closure from the Lower Jurassic to the Tertiary. Pancontinental noted the lead had sands onlapping the crest which indicated a growth structure. The new 3D survey is scheduled to kick off in November, with interpreted results expected to be available by the second quarter of next year. The joint venture is considering starting drilling operations in the licence areas next year.

DOLPHIN GEOPHYSICAL HAS received a Letter of Intent by Shell South Africa Upstream BV for up to 8,000 sq km 3D seismic acquisition, offshore South Africa. The survey will be acquired by M/V Polar Duchess and will commence in Q4 2012. M/V Polar Duchess is a purpose built high-end 3D seismic vessel, capable of towing 14 streamers at 100 m separation. "We are very pleased to be working for Shell on this survey, our first for a super-major” says Atle Jacobsen, CEO. “This is the second high profile 3D job that Dolphin have been awarded this month and is a confirmation that Dolphin Geophysical have developed into becoming a recognised supplier of seismic services after only 18 months in business".

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40 Oil Review Africa Issue Five 2012

Namibia seismic survey steaming ahead SERICA ENERGY'S SEISMIC operations are progressing as planned offshore Namibia. The 10-streamer vessel Polarcus Nadia started the 4,150-sq km 3D survey in the Central Luderitz basin is nearly complete. Data acquired to date has been of good quality, according to Serica , and should lead to fuller delineation of numerous potentially significant prospects that have already been identified.

Beach starts seismic survey on Lake Tanganyika BEACH ENERGY LTD started a 1,800-km 2D seismic programme on the South block of Lake Tanganyika, Tanzania. Early results indicated a rift structure and style similar to that seen in the Lake Albert portion of the rift where Tullow Oil has discovered oil. Fugro Oceansismica is doing the survey that is expected to last two months followed by seven months of interpretation. A local ferry, MV Mwongozo, was converted into a seismic acquisition vessel including quality control equipment to make possible identification of prospects and leads of interest. Infill seismic is scheduled to follow the 2D work. In June 2010, Beach signed a Production Sharing Agreement with the Tanzanian Petroleum Development Corporation and the government of Tanzania covering the Lake Tanganyika South block. Since that time, Beach has conducted aerial high-resolution gravity and magnetic surveys and a bathymetry survey over the lake, which has satisfied its financial commitment for the first four year term of its exploration agreement with the government.

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Gas

Apache makes first offshore Kenya gas discovery AUSTRALIAN JOINT VENTURE partner, Pancontinental Oil & Gas, has revealed an important new gas discovery has been made in Kenya with the Mbawa deep-water exploration well. The company announced the Mbawa-1 well, operated by Apache, measured 52 net metres of gas pay in the primary Cretaceous sandstone target. The well is still drilling towards an expected total depth of 3275 m, and there is a secondary target reservoir along the way. Pancontinental chief executive, Barry Rushworth, said Mbawa is "the first ever substantive hydrocarbon discovery offshore Kenya. With drilling continuing to a deeper exploration target, these interim results may be the first part of the story in this well, and they are certainly just the beginning of the main story of oil and gas exploration offshore Kenya.” The well is being drilled using the drillship Deepsea Metro 1 in a water depth reaching 860 m.

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BP and Eni make double gas find off Egypt BP AND ENI subsidiary International Egyptian Oil Company (IEOC) have reported two gas discoveries at Taurt North and Seth South in the pair’s North El Burg offshore concession in Egypt’s Nile Delta. The British supermajor said the pair of finds were the fourth and fifth to be made in the concession following the Satis-1 and Satis-3 Oligocene deep discoveries and last year's Salmon-1 shallow Pleistocene discovery. The two latest wells were drilled by IEOC on behalf of operator BP using the Scarabeo IV rig in water depths of 110 and 78 m respectively. “The wireline logs fluid samples, and pressure data confirmed the presence of gas in one Pleistocene interval in Taurt North and two PlioPleistocene intervals in Seth South,” BP said. The concession lies in water depths of 60 to 100 m, and is situated between the BP-operated Ras El Bar development concession and the IEOCoperated offshore Baltim development concession. At Ras El Bar BP operates the concession on a 50 per cent stake under its Pharaonic Petroleum Company joint venture with Egyptian General Petroleum Company (EGPC) and Egypt Natural Gas Holding (Egas), with IEOC holding the other half. In June, BP and IEOC saw first gas three months early from Ras El Bar’s Seth field, where output is expected to reach 170 mmscfd. BP has interests in a total of eleven concessions in the Nile Delta, with operatorship of six.

Tanzania to revise gas drilling deals TANZANIA WILL REVIEW all contracts with oil and gas exploration companies by the end of November, as the East African nation overhauls its laws following a string of major natural-gas discoveries. The government will examine more than 20 contracts to ensure that they are in the "best interests of the Tanzanian people," said Eriakimu Maswi, permanent secretary at Tanzania's Energy and Minerals Ministry. The government also wants to ensure Tanzania's state energy firm plays an active role in oil and gas projects. Tanzania's move comes amid a growing trend across the continent, where governments of newly resource-rich nations attempt to balance their citizens' desire for a share of any future wealth with sufficient incentives to attract foreign investment. East Africa's coastal waters are estimated to hold up to 441 tcf of natural gas. Tanzania, whose own reserves estimates have nearly trebled after discoveries by firms like Statoil, Ophir Energy and BG Group, is expected to join Kenya and Mozambique as a major energy export hub to Asia. Like Tanzania, Mozambique is also mulling a new law to replace its existing resources legislation.

S08 ORA 5 2012 Gas_Layout 1 02/10/2012 17:48 Page 43

22-25 April 2013 Tripoli International Fairground

International showcase and conference for oil exploration, production, refining and petrochemicals, where service and supply companies meet oil and gas producers and refiners. Exhibit sectors include:

and production technology LNG Pipelines ExplorationRefinery development HSE Training The exhibition runs alongside Infrastructure Libya 2013 – the International Exhibition & Conference for Libya’s Rebuilding Programme. For further information go to:

Gas

S08 ORA 5 2012 Gas_Layout 1 02/10/2012 17:48 Page 44

Eni, Vitol sign Ghana gas accord

KBR wins contract for offshore Angola FPSO

ENI, ALONGSIDE VITOL, has signed a memorandum of understanding (MoU) with Ghanaâ&#x20AC;&#x2122;s government to develop gas in the Offshore Cape Three Points (OCTP) block in the Tano basin. The MoU outlines the key principles for future development of the discoveries and commercialisation of the gas within the contract area. The MoU focuses mainly on the domestic gas market, in which Eni and its joint venture partners want to be at the forefront. The agreement is in line with Eni's growth strategy in the region and reaffirms the company's leading position in exploiting indigenous gas resources and contributing to the socio-economic growth of the countries where it operates. Eni will operate the OCTP block with a 47.222 per cent stake, with Vitol holding a 37.778 per cent interest and state-owned GNPC 15 per cent. VitoEni has been present in Ghana since 2009 and currently operates the OCTP and Offshore Keta exploration blocks.

KBR HAS BEEN awarded a feed contract to perform work for the topsides and hull associated with a new-build, double-sided, single-bottom hull Floating Production Storage and Offloading (FPSO) vessel. The FPSO will be situated offshore Angola and FEED is scheduled to begin immediately, with a duration of 12 months. KBR's scope covers the permanently moored FPSO using a spread mooring system. The vessel will be capable of storing a minimum of 1mn BBLS and housing 130 persons on board. The topsides will utilise a single train designed to process 80,000 bopd and 90 mmscfd at an export pressure of 3,500 psi. The water injection facilities will be designed to inject up to 130,000 barrels of water per day. Services for the project will be based out of KBR's offices in Houston, Gothenburg and Luanda. KBR's Luanda office will play a major role in supplying local employee content for the project. "This project builds upon KBR's long-standing commitment to the African region and further solidifies our position as a leading FPSO provider," said Dennis Calton, President, Oil & Gas. "KBR has been present in Africa for nearly 60 years and has executed numerous projects in Angola. I am confident that KBR's successful completion of this project will position us for additional services during the EPC phase." Produced gas will be transported via pipeline and stabilised crude oil will be kept in the FPSO hull tanks and exported through a deepwater single point mooring export terminal. The crude will be transferred using a mid-water oil offloading line from the FPSO to the SPM buoy. Produced gas will be dehydrated and transferred via a gas export line to a client-owned facility. The design service life of the FPSO facility is 20 years.

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Ophir boosts resource estimates with BLock R OPHIR ENERGY HAS announced the successful completion of its 2012 three-well drilling programme in Block R, Equatorial Guinea. All three wells exceeded pre-drill recoverable resource estimates. The Fortuna West-1 (R6) exploration well in Block R, Equatorial Guinea has added an additional 1.0 tcf (169 mmboe) of recoverable resources. The well encountered gas in the primary target of the western lobe of the Fortuna Complex, in the secondary deeper Viscata prospect and there is further potential upside in the Felix prospect. Nick Cooper CEO of Ophir said: "The success of Fortuna West-1 across multiple targets improves our overall understanding of the Fortuna Complex and Viscata Channel Levee Complex within Block R. The well discovered over 1.0 tcf of recoverable gas, and has significantly derisked other exploration targets within the Block. Based on the results of this three-well drilling campaign, we have increased our 2C resource estimate to 3.0 tcf, and have reduced the risk on the remaining estimated 10 tcf of inventory. The Fortuna wells, combined with the Tonel discovery, provide confidence to proceed with commercialising the gas via LNG export. A follow-up exploration and appraisal drilling programme in 2013 will further advance this valuable gas asset toward development."

Drilling giants reach new depths as offshore exploration evolves DEPLETING SHALLOW WATER reserves and a lack of new shallow water discoveries means that offshore exploration and production activity in deepwater regions is becoming a new fashion, stated a report by GBI Research. The report said that the search for hydrocarbons in more challenging areas has been on the rise, as advances in drilling technologies have led to the discovery of giant deepwater oil and natural gas fields worldwide, prompting ambitious International Oil Companies (IOCs) and National Oil Companies (NOCs) to drill in remote offshore areas in search of fresh fossil fuel reserves. Until the early 1990s, offshore exploration and drilling in deepwater areas was considered an economically unattractive option. However, with the near-complete exploitation of shallow water and onshore resources, and recent advances in drilling technology, deepwater exploration is now feasible and profitable, the research shows. Offshore rigs such as advanced semisubmersibles are capable of drilling in water depths

exceeding 1,524m, and some sixth-generation enterprise-class drillships possess water depth capabilities of up to 3,658m. This has led to a significant rise in deepwater and ultra-deepwater Exploration and Production (E&P) activity across the globe, and governments worldwide are promoting the industry in hopes of achieving energy self-reliance, the research found. Offshore West Africa and offshore Angola in particular are proving to be hotbeds in terms of deepwater offshore drilling activity and expenditure, it discovered. As oil and gas E&P activity moves into deeper water depths, the market for the services of deepwater drilling contractors and offshore rigs operating in deepwater and ultra-deepwater environments will witness strong growth, the report claimed. It added that offshore day rates for drillships and semisubmersibles are already steadily rising, and this in turn will drive the construction industry for offshore drilling technologies.

West Africa increasing O&G e&p in deep offshore areas ENI HAS MADE the first oil discovery in the Offshore Cape Three Points (OCTP) block, located in the Tano Basin offshore Ghana, about 50 km off the coast of Ghana. The discovery is relevant as it may have the potential for commercial development and confirms the importance of the block also in terms of the presence of oil, as well as natural gas and condensates. Eni plans for the immediate drilling of other wells to delineate the size of the discovery and confirm the feasibility of commercial development. The discovery was made through the Sankofa East-1X well, which reached a total depth of 3,650 m, in 825 m of water, and encountered 28 m with gas and condensate and 76 m of gross oil pay in Cretaceous sandstones. During the production test, carried out in the oil level, the well produced about 5,000 high quality bopd. The flow rates, during the production test, were constrained by surface infrastructures. In addition, there are ongoing engineering studies for the development and commercialisation of gas reserves of the block in accordance with the principles sanctioned in the Memorandum of Understanding recently signed by Eni, Vitol and Ghana National Petroleum Corporation (GNPC) with the Minister of Energy of Ghana. The MoU focuses particularly on the domestic gas market, in which Eni and its joint venture partners wish to play a prominent role. Eni, through its subsidiary Eni Ghana Exploration and Production Limited, is the operator of the OCTP block with a 47.222 per cent share. Other partners are Vitol Upstream Ghana Ltd, with a 37.778 percent share, and state company GNPC with a 15 percent share. GNPC has an option for an additional 5 percent share. Eni has been operating in Ghana since 2009 and currently operates two exploration offshore blocks OCTP and Keta.

Apache signs up Foster Wheeler in Egypt SWISS-HEADQUARTERED FOSTER Wheeler has signed a three-year framework agreement with Apache Corporation to provide consultancy services to its upstream operations in Egypt. Foster Wheeler said a subsidiary of its global engineering and construction group had signed the deal with Apache subsidiary Apache Khalda Corporation, a joint venture with state player Egypt General Petroleum Corporation.

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Apache Khalda Corporation, a joint venture with state player Egypt General Petroleum Corporation, has retained Foster Wheeler to work on design, engin

The services to be provided by Foster Wheeler under the framework agreement include design, engineering and project management to assist Apache in the development and implementation of upstream projects in Egypt. The US independent is currently chasing six blocks in Egyptâ&#x20AC;&#x2122;s latest onshore round. The pair of companies previously worked together last year when Foster Wheeler secured a deal with Apache Khalda to provide project management consultancy services on a compression project for the Qasr gas condensate field.

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Total to spend $650mn in Uganda TOTAL EXPECTS TO drill eight exploration wells in Uganda by the end of next year, and will spend about US$650mn on its activities in the same period, a senior company official said. The company had entered Uganda’s petroleum industry earlier this year when it and China’s CNOOC each took a third of Tullow Oil’s exploration assets in the country for a total of US$2.9bn. "Total E&P Uganda is currently continuing the exploration, delineation and appraisal campaign initiated by the previous operators," Total E&P Uganda general manager Loic Laurandel said. "The first oil exploration well will be drilled by the end of 2012 and eight new exploration wells will be drilled by the end of 2013."

Uganda discovered oil in its west along the border with the DRC in 2006. Production had been expected to start early this year but wrangling over tax and other issues delayed development. Laurandel said Total, which operates Block 1 on the northern tip of Lake Albert, would spend about US$650mn on exploration and appraisal drilling and seismic data acquisition by the end of next year. Tullow said the refinery's capacity should not exceed 60,000 bpd to be attractive to investors but the government said a facility with a maximum output of 120,000 bpd was viable and could easily attract investors. Total supports the project but Laurandel said the company could not comment on whether it will invest

in it or state its preferred size of facility because disclosure of its positions was likely to undermine discussions with the government. "Sufficient resources exist (1.8 to 2.2bn barrels) to deliver a plateau production rate of 200,000 to 230,000 bpd in support of an appropriately sized refinery," Reuters quoted him as saying. "We think that an international crude oil export pipeline, combined with an optimally sized refinery will provide the maximum benefit to the wider Ugandan economy." Uganda is expected to conduct a licensing round for hundreds of square kilometres of exploration acreage after parliament passes new oil laws expected by the end of this year.

Tanzania delays round launch

Simba gains 100% stakes in 3 PSCs in Chad

TANZANIA HAS POSTPONED the launch of a keenly-awaited deep-water licensing round originally scheduled for September pending a parliamentary vote on a new gas policy in October. The country is set to offer nine new deep-water blocks, including one ultra-deep permit, in its fourth licensing exercise that will focus on acreage to the south. The latest round was due to be launched at a 13 September roadshow in Houston, with another to be held in Singapore and one in London in October, with a similar event scheduled for March in Arusha, Tanzania. Bids were due to be submitted during a nine-month period that closes in the middle of May 2013, when the offers will be opened in Dar-es-Salaam. However, state-owned Tanzania Petroleum Development Corporation (TPDC) said in an undated statement that “the roadshow schedule will start again immediately after the parliamentary ratification” of the new gas policy, following the vote next month. Completion of the bid round data package is still on schedule and will be available for potential bidders by the end of this month, giving them more time to evaluate the blocks before the delayed round launch, TPDC stated. A series of gas discoveries by BG Group and Statoil off Tanzania, along with similar finds off Mozambique, have stoked exploration interest in the emerging East Africa play.

CANADIAN EXPLORER, SIMBA Energy has secured production sharing deals for three Chad blocks to further expand its African asset portfolio. The company put pen to paper on Monday on a so-called Protocole d’Accord under which a work programme for the first year of exploration on the onshore tracts must be finalised by 20 October. Simba will hold 100 per cent stakes in all three prospective concessions, each of which could be “a company-maker in its own right”, according to managing director for operations Hassan Hassan. Two of the blocks, Chari Sud Block I and Chari Sud Block II, cover a total area of more than 10,000 sq km and are located south of the Mangara and Badila oilfields being developed by Griffiths Energy and Glencore International. The pair of concessions, located in the southern margins of the Doba and Doseo basins, are believed to have structural similarities to the producing fields, while pipeline infrastructure is located in the vicinity of Chari Sud Block I. The third concession, Erdis Block III, spans 15,700 sq km in the Erdis basin where numerous oil discoveries have been made to the north in Libya, where it is called the Kufra basin. Simba also holds interests in blocks in Kenya, Republic of Guinea and is waiting to finalise a PSC for Block 3 in Mali, while it also has applications pending for blocks in Liberia and Ghana.

Bowleven nets Kenyan acreage UK JUNIOR BOWLEVEN has added a new region to its African portfolio as it snapped up a large slice in an onshore Kenyan play. The company has farmed into Block 11B by taking 50 per cent from local player Adamantine Energy. The “extensive and highly prospective exploration acreage position” gives BowLeven exposure to a new hydrocarbons province, following on from its position in Cameroon. The block covers about 14,000 sq km encompassing the Loeli, Lotikipi, Gatome and South Gatome basins.

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“The basins are to the north of the Lokichar Basin where a significant oil discovery has been made in recent months with the Ngamia-1 well,” BowLeven said. “Analysis of the existing gravity and magnetics and seismic datasets suggest the basins in Block 11B are of similar form to Lokichar and analogous geological plays and petroleum system elements are expected.” BowLeven is to fund an initial work programme of geophysical and 2D seismic, expected to cost around US$10mn.

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Ugandan oil one year later than planned TOTAL EXPECTS TO pump commercial oil production from its fields in Uganda to start from 2017, a year later than previous estimates had suggested, as the foreign firms charged with developing the country's nascent energy sector try to overcome a host of issues that have delayed operations. Total entered Uganda earlier this year after a longdelayed deal by British wildcatter Tullow Oil PLC to sell two-thirds of its exploration assets in the country to the French major and China's Cnooc. was finally approved. "We are working closely with our partners and the Ugandan government to get the necessary approvals to enable us deliver first oil by late 2017," said Loic Laurandel, Total E&P Uganda's general manager. However, Mr. Laurandel's assessment of when oil production will commence is a full year later than initially hoped. When the partners completed the US$2.6bn deal in February, Tullow

Oil Exploration Director Angus McCoss said first oil should come by 2016. The hold-up has been due in large part to wrangling between the Ugandan government and the partners over how the fields should be developed and the crude best used. The partners can only begin operations in earnest once the government approves its development plan. First commercial oil will likely arrive 36 months after the approval of the development plan, Tullow has said. Total, which plans to invest about US$650mn in exploration and appraisal drilling in Uganda by the end of next year, expects initial output of around 20,000 barrels of a day from its block on the northern tip of Lake Albert. This will gradually rise before reaching 200,000 to 230,000 bpd by 2020, said Mr. Laurandel. According to Mr. Laurandel, Total will also seek more exploration licenses in Uganda once the country opens the next licensing round, expected

later this year or early next year. "We are committed to extend our stay in Uganda as much as we can, we shall definitely seek more licenses," Mr. Laurandel added. Uganda has six unlicensed oil blocks and at least 10,000 square kilometers of relinquished acreage in the Lake Albertine Rift basin which will be auctioned during the next licensing round. The next licensing round will be commenced after the enactment of three oil bills, which are currently before parliament

Chevron confirms Sierra Leone blocks CHEVRON HAS CONFIRMED earlier reports that it scooped a pair of deep-water block awards in Sierra Leone's latest awards round. The US supermajor has been handed a 55 per cent interest in blocks SL-08A and SL-08B where it will also be operator. Reports in recent months have shown that Chevron had won block interests off Sierra Leone and would be partnered by Odye and Noble. However, the size of each party's stake, as with other awards in the

country's concession round, was being discussed. Noble is picking up a 30 per cent stake in the play with Odye going home with 15%. Sierra Leone National Oil Company has a 15 per cent back-in option at final investment decision time. The two blocks are situated between 120 and 180 km off Sierra Leone in average water depths ranging from 1500 - 3000 m. The total acreage is spread over 5500 sq km.

BG Group begins appraisal at Jodari Field

South Sudan to pump as soon as possible

OPHIR ENERGY HAS resumed the Tanzanian drilling campaign to be executed with BG Group, its partner in this Joint Venture. The multi-well programme commences with appraisal and satellite exploration around the Jodari field in Block 1 offshore Tanzania. The first three wells in this campaign will be Jodari South-1, Jodari North-1 and a re-entry into Jodari-1. The current drilling programme will focus on further defining the resource potential of the Jodari discovery. In March, the Jodari-1 discovery well proved 4.5 tcf of gas in place in the Lower Tertiary intraslope channel play. To date the Ophir-BG Joint Venture has discovered 13.5 - 21 tcf of gas-in-place across Blocks 1, 3 and 4 offshore Tanzania. The Deepsea Metro 1 (UDW drillship) has now returned to Block 1 and will drill the top-hole section of Jodari North-1 before moving to drill Jodari South-1 and a side track from Jodari South into the main Jodari field. The rig will then return to complete Jodari North-1. A Drill Stem Test (DST) will be performed in 1Q 2013. Jodari North-1 is located 40 km NE of the port of Mtwara and is approximately 6 km NNW of the Jodari-1 well location. Jodari South-1 is located approximately 35 km NE of Mtwara and is approximately 3.5 km SW of the Jodari-1 well location. Combined, these three wells will confirm reservoir parameters across the Oligocene aged main reservoir of the Jodari complex.

THE OIL COMPANY Dar Petroleum has said it will begin oil production in South Sudan as soon as possible following a security deal signed with Sudan, though getting back to full production remains several months away. Dar Petroleum President Sun Xiansheng promised investors and South Sudan's government that the company will eventually return production to an average of 180,000 bpd. South Sudan in January shut down its oil production after accusing Sudan of stealing its crude. When South Sudan peacefully broke away from Sudan last year, it inherited the majority of the region's oil. But South Sudan's oil must be pumped through pipes owned by Sudan, which said it had taken the south's oil in lieu of unpaid fees for the use of its export and processing facilities. When tensions increased, the south shut down its industry, costing both sides millions in lost revenue. The two sides have signed agreements after four days of talks between both countries' presidents. Those agreements paved the way for a resumption of southern oil production. In August, South Sudan Oil Minister Stephen Dhieu Dau said it could take between four and six months before the Upper Nile fields reach full production again. Dar Petroleum's general manager of exploration and production, Chen Huanlong, said that estimate is correct. Huanlong said the company will need to "warm up the pipes" for one month. After that, Huanlong said they would "approach the production plateau" in three months. But Huanlong said this would happen only if the government contracts and orders were prepared as soon as possible. "Dar Petroleum contributes 80 to 90 per cent of government revenue. We are the national builders. We will change the nation," said Baidzawi Chemat, Dar Petroleumâ&#x20AC;&#x2122;s general manager of finance and services. According to him, if Dar Petroleum can deliver on its promised production target, it will mean around 65mn barrels each year worth around US$5bn for South Sudan.

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Canada Oil Junior moves into Sudan EMPEROR OIL, A Canadian Junior Oil & Gas Company, has expanded its focus into Sudan – a country where China is leading the foreign oil investment arena having more than 200 Chinese companies active in Sudan. With major players dominating the arena such as China, Malaysia, and India, Emperor Oil is a US company determined to make a name for itself in this part of the world. In 2011, after the separation of Sudan and South Sudan, SUDAPET (Sudan’s state owned oil enterprise) has been accelerating its oil exploration and development activities in Sudan where there is still vast potential for oil reserves. There are reportedly plenty of blocks that have not been fully explored, so there could be more finds. As a result, Sudan made licensing rounds available. They are rated the third largest producer in subSaharan Africa after Angola and Nigeria with some 6.6bn barrels in reserves. Together, Sudan and South Sudan produce 460,000 bpd and there appears to be tremendous unexplored potential. Emperor Oil has entered into an MOU with State Petroleum Overseas Inc. to assist in the development of three previously discovered oil fields in Sudan’s Block 7 oil concession. The discovery wells (one in each field) are believed to have significant production potential and Emperor Oil is eager to capitalise on the vast opportunities they believe are available in the region.

Maersk Drilling secures offshore West Africa contract MAERSK DRILLING IS expanding its activities in West Africa with the signing of a contract for the jack-up Maersk Endurer with Addax Petroleum, owned by Sinopec, which is one of the largest oil and gas producers in the world. The contract duration is two years and the value is around US$100mn. Expected commencement is late October 2012. “We are pleased to have signed this contract with a very experienced operator in West Africa, which is a priority market to us due to its significant resources and importance to the global oil and gas supply,” Maersk Endurer. says Martin Fruergaard, Chief Commercial Officer in Maersk Drilling. The Maersk Endurer is a harsh environment jack-up. It was acquired by Maersk Drilling in 1996 and significantly refurbished and upgraded for work on the challenging Shearwater field in the UK Sector of the North Sea. The extensive modification scope covered, amongst others, a new accommodation block, new drillfloor/derrick and full compliance for HPHT operations.

RWE confirms Nile Delta discover extension RWE DEA EGYPT has confirmed an extension of the North Sidi Ghazy-1x discovery in the Nile Delta with a successful development well.NSG-1-2 was drilled in the North Sidi Ghazy structure and reached TVD of 2,843 m below the sea surface. The well confirmed the extension of gas resources and Messinian (Abu Madi formation) reservoir properties on the eastern side of the field.RWE Dea has now moved the Weatherford 94 rig to the South Sidi Ghazy-1-2 well to develop the northern extension of the South Sidi Ghazy-1x discovery.The North Sidi Ghazy-1x gas discovery flowed about 1 mmcmd of gas on a 50/64 in. choke.The latest well has been temporarily suspended and will be completed as producer, along with other wells, later this year.

Molopo gets S African production right AUSTRALIA-LISTED MOLOPO Energy has been awarded its first production right in South Africa, covering a 200,000 ha area in the Free State province. Molopo made the production right application of the Virginia licence area based on its previous work during the exploration phase during which time the area was estimated to hold proven plus probable reserves of about 23 bcf. The Australian company said its initial phase of development of the licence area would involve the tie-in of four of the 11 pilot production wells, which are currently producing at about 1.2 mmcfd. Initial output from the development is expected

to be about 600,000 cfd of natural gas which will be compressed for transportation. The capital investment outlined in the production right is about US$15.6mn, with US$2.5mn to be invested in the first year, US$4mn in the second and US$8.9mn in the third year. Molopo said the timing and detailed scope of the development plans for the licence area would be finalised over the coming months. It added that the longer, full field development could result in the development of more than 200 wells, depending on success in further delineation of the resource as well as progress on gas commercialisation opportunities.

PTTEP hits Algerian double THAILAND'S STATE-RUN PTT Exploration & Production has discovered two oilfields on the Hassi Bir Rekaiz project in Algeria. The OGB-1 exploration well hit oil in the Ordovician reservoir which flowed at an average rate of about 485 barrels per day during testing. PTTEP noted that the Triassic Argilo Greseux Inferieur (TAG-I) reservoir also exhibited oil flows but would need to be assessed further. The TAG-I reservoir was the same formation in which oil was encountered in the Rhourde

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Terfaia-1 wildcat which was drilled earlier this year and flowed at a rate of about 1000 bpd of oil and 300,000 cfd of gas during testing. PTTEP said the fifth exploration well to be drilled in the Hassi Bir Rekaiz project area, BOG-1, also hit oil in the Ordovician and TAGI reservoirs. It added the well flowed at an average rate of about 553 bpd from the Ordovician reservoir and 1870 bpd from the TAG-I reservoir during testing.

PTTEP and its partners are currently carrying out the first exploration phase at the Hassi Bir Rekaiz project which will see them drill a total of nine exploration wells. The sixth well in the programme is expected to be spudded by the end of the month. PTTEP operates the Hassi Bir Rekaiz project, holding a 24.5 per cent stake, with China National Offshore Oil Company also holding 24.5 per cent and Algerian national oil company Sonatrach holding the remaining 51 per cent equity.

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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.

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

Oil 29 9 2 7 0 11 13 0 1 11 83

Gas 16 0 0 0 0 0 4 0 1 0 21

Misc 1 0 0 0 2 0 1 0 1 12 17

LAST MONTH Oil 30 6 2 6 0 9 13 0 0 13 79

Gas 15 0 0 0 0 0 3 0 1 1 20

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

LAST YEAR Oil 23 7 7 4 0 0 12 0 2 9 64

Gas 7 0 0 0 0 0 3 0 0 0 10

Misc 1 0 0 1 1 0 1 0 1 0 5

Source: Baker Hughes

Tullow spuds Paipai well in Kenya AFRICA OIL HAS announced the spudding in Kenya of the Paipai-1 exploration well located in onshore Block 10A, on September 29, 2012. The well is planned to drill to a total depth of 4,112 m and will test Cretaceous and Jurassic sandstone targets. The well is operated by Tullow Oil who hold a 50 per cent working interest. Africa Oil holds a 30 per cent working interest in the Block. The Paipai-1 will be drilled using the Sakson PR-5 rig and is targeting gross best estimated prospective resources of 121mn barrels by the Company's independent resource evaluator. Keith Hill, President and CEO of Africa Oil, commented, "The Paipai well will test Cretaceous and Jurassic targets in the Anza graben, whose geologic history is comparable and on trend with producing basins of Sudan. Paipai-1 will test a large structural trap in what is considered to be

an oil-prone area of the Anza basin. Legacy wells have encountered significant oil and gas shows, but newly acquired seismic surveys have helped improve mapping and identify the Paipai prospect as a favorable and potentially high-impact exploration target. A discovery at Paipai would extend the producing plays of Sudan into Kenya and open a potentially significant and new petroleum province within Kenya where the company is already implementing an accelerated exploration programme after the Ngamia-1 discovery in the Tertiary Rift Play earlier in the year. With plans in place for three drilling rigs to be operational before the end of the year, the company is entering an exciting period of activity with multiple high impact exploration targets expected to be drilled before the end of 2013."

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Anadarko tags Mozambique LNG facility at US$15bn ANADARKO PETROLEUM IS in talks with Eni to build an LNG plant in Mozambique as part of a plan to jointly develop their recent major gas discoveries off the East African country's coast. Large natural gas discoveries since late 2011 off the coasts of Mozambique, Tanzania and, most recently, Kenya, have transformed East Africa into one of the world's most promising energy provinces, potentially challenging Qatar and Australia for key export markets in Asia. "We are in talks with Eni about combining efforts both on the offshore development and on building a liquefaction facility onshore," said Scott Moore, Vice President of Marketing. After the most recent discovery in June, Anadarko said the high-end estimate for total gas in the Rovuma-1 find is approaching 100 tcf. A

consortium led by Anadarko plans to bring the gas to shore, where it will be liquefied and shipped to Asian and other markets. The total cost of offshore development and construction of a new two-train liquefied natural gas terminal is estimated at around US$15bn, said Mr. Moore, who was speaking on the sidelines of a conference in Singapore. A final investment decision is expected next year, with the first LNG possibly hitting the market in 2018. The Anadarko discovery is located close to another huge reserve found by Eni, which has discovered close to 70 tcf of gas in the region, of which 50 trillion are part of the same geological structure as the Anadarko discovery. An Eni spokeswoman confirmed talks are ongoing with Anadarko on joint offshore development,

Lamu-Juba oil pipeline to cost $3bn SOUTH SUDAN HAS finally agreed to transport its oil via a pipeline from Lamu port. The country had earlier said that they would transport their oil by road instead. The 2,000-km pipeline is estimated to cost approximately US$3bn. The pipeline will allow South Sudan to export its oil via the Kenyan port of Lamu, freeing the landlocked country from reliance on a route through Sudan. The route had earlier this year been shut down following the two countries

disagreement over how much the Juba government should pay to transport its oil output through Sudan. This has however been resolved. Construction of the pipeline is expected to begin by June 2013 and last two years. It will be able to transport between 700,000 barrels and one million barrels of Southern Sudanese crude per day. Though the country says they donâ&#x20AC;&#x2122;t have the money now, South Sudan has a total of seven billion in proven reserves.

Uganda govt invites partners for oil refinery

Review set for S Africa refinery project

THE PERMANENT SECRETARY in the Ministry of Energy and Mineral Development, Fred Kabagambe-Kaliisa said the government is inviting strategic partners and producing companies to be lead developers in the construction of an oil refinery estimated to cost about US$2bn. Mr Kabagambe-Kaliisa, in a recent interview, added that the coinvestor has to be a person well known in the oil industry and with a dependable profile. "We are talking about US$2bn. Noone in Uganda has that kind of money. Of course government can offload its share onto the market and all Ugandans have a right to buy shares," he was quoted as saying. He added: "We have done our market research. If you take the core market segment alone, buyers include Uganda, Eastern Congo, Rwanda and Burundi and for this market alone, 60,000 bpd is enough. This market alone can sustain the refinery and we will stop importing fuel." The permanent secretary said Uganda will start producing oil for power generation in 2014 with production of at least 10,000 bpd and in 2015, they would like to have the first phase of the refinery in place and then, in 2017, have the final phase of the refinery with about 60,000 barrels which could be expanded later. He also clarified that there no oil has been produced for commercial purposes but there has been prolonged testing in the Buliisa area. Mr Kabagambe-Kaliisa added that they have to get the oil out for chemical analysis of texture to determine what type of refinery will be required. About ten barrels were taken abroad where there are high-tech labs.

ENERGY MINISTER DIPUO Peters has recommitted government's support for Project Mthombo, the much-awaited PetroSA oil refinery at Coega. In reply to a question from an ANC MP, Peters said that PetroSA and its potential partner, the Chinese state-owned group Sinopec were reviewing the business case for the construction of a new refinery at Coega. Organised business in the Eastern Cape believes Mthombo has the potential to be a major catalyst for socio-economic transformation of the province through job creation. Peters said her department was still committed to Project Mthombo. She said the review of the business case included aspects such as the size of the refinery, the schedule and the related costs. Peters also said such an infrastructure project would create a "massive number of jobs" during construction and sustain increased levels of economic activity during operations. On electricity, Peters said inflation would be among the criteria used to determine future electricity tariffs. In a written reply to a parliamentary question posed by the Democratic Alliance, Peters said she would ensure inflation-based pricing was part of the overall tariff structure for the next multi-year electricity price determination. "The pricing policy covers all the issues that must be taken into account when dealing with tariff determination, including the rate of returns as well as associated economic impacts. Inflation does get considered in the pricing methodology," her reply stated. Peters said a study of South Africa's competencies, capabilities and needs for the proposed nuclear build programme had been submitted to the International Atomic Energy Agency (IAEA). Replying to a question from DA MP Lance Greyling, Peters said such a self-assessment report was required by the IAEA, and its findings would be made known once the process was completed. In terms of the 2010 Integrated Resource Plan, the government plans to build between six and eight nuclear reactors that would eventually generate 9600MW of power.

Geoffrey Muleme

54 Oil Review Africa Issue Five 2012

S10 ORA 5 2012 Downstream_Layout 1 02/10/2012 17:49 Page 55

Tanzania seeks Statoil’s help for LNG terminal

NIGERIAN OIL AND gas firm Orient Petroleum Resources disclosed that by the December 2013 it would commence the refining of 20,000 bpd of crude oil at a new oil refinery in the south-eastern part of the country. Despite being one of the top ten oil producers in the world, Nigeria imports petroleum products and supplies its local demand at a subsidised rate accumulating heavy financial burden on budget. In 2012, US$5.5bn of the country’s US$29.3bn total budget was swallowed by fuel subsidy. The prolonged dilapidated state of its refineries has contributed to the sour development. Previous efforts to build new refineries were cancelled or have been unexplainably sluggish. According to Reuters, Africa’s biggest oil producer has only four refineries at the moment, with an estimated production capacity of 445,000 bpd but their eventual production is only 30 per cent of the reported capacity. OPR Chairman Emeka Anyaoku said at the inauguration of the project: “We expect that by the end of next year we should be refining 20,000 barrels of oil every day and gradually after that we will build up to 35,000 then 55,000 and possibly higher.”

TANZANIA DEPUTY MINISTER for Energy and Natural Resources, Stephen Masele, has been in discussions with Statoil Vice President, Tim Dodson, to convince BG Group PLC to support building an LNG plant in Tanzania. "Despite being a costly project in its implementation, its completion will be very beneficial to the government and the country at large and that is why we are insisting on developing it in dry lands," Masele said. Dodson, however, remained sceptical, noting that with 9 tcf of natural gas already discovered in Tanzania it is insufficient at present for a viable LNG project. He did say that Statoil can talk to BG to see if building an LNG processing facility might be possible through co-operation, with either the Tanzanian government or foreign partners. The costs involved are not insignificant. Building an LNG plant costs at least US$1.5bn per 1mn mt per annum, a receiving terminal costs US$1bn per 1 bcf per day throughput capacity and LNG tanker vessels cost US$200mn-US$300mn apiece. Generally, since the early 2000s, competition and new technologies have seen the prices for construction of LNG plants, receiving terminals and vessels fall, making LNG more competitive as an energy source, but recently rising material costs and demand for construction contractors have driven up prices. "Roughly, the host country can expect to get around 40 per cent of total revenues depending on the tax regime and the production sharing agreement," said World Bank official Jacques Morisse. "This means for Tanzania around 7 per cent of its projected (gross domestic product) or about a third of its current fiscal revenues if all above reserves can be exploited. These fiscal resources, while considerable, will not be sufficient to transform Tanzania."

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log on tto o www www.portwest.com w..p portwest.com or call call or sales sales tteam eam aatt +44 (0) 1709 894575 89457 75 or email in info@portwest.com fo@portwest.com o Oil Review Africa Issue Five 2012 55

Downstream

Orient to increase Nigerian refineries

S11 ORA 5 2012 Technology A_Layout 1 02/10/2012 17:12 Page 56

Project Databank & Project Focus Compiled by Data Media Systems

OIL, GAS AND PETROCHEMICAL PROJECTS Project ADDAX - Oron Redevelopment & Extension BRASS LNG - Brass River LNG Plant CHEVRON NIGERIA - Escravos Gas-to-Liquids (GTL) Project CHEVRON TEXACO - Agbami Oil Field Development Ebok Development FLEX LNG - LNGP1 (Floating LNG Production)

Sector Offshore Gas Gas

Facility Budget Oil & Gas Field 400000000 Liquefied Natural Gas (LNG) 3500000000 Gas to Liquids (GTL) 1700000000

Status EPC EPC ITB EPC

Start Date Q3-2005 Q4-2004 Q3-2001

Completion Date Q4-2012 Q4-2016 Q4-2013

Offshore Oil Offshore

5000000000 450000000 500000000

EPC EPC EPC

Q1-1998 Q2-2007 Q1-2006

Q4-2014 Q2-2013 Q4-2015

FPR - Araromi Refinery Project MART RESOURCES Umusadege Field Development NNPC - Olokola LNG (OKLNG) Plant Ofon Field Development Phase 2 Okoro and Setu Fields Development OYO Field Development Southern Swamp Associated Gas Solution Project (SSAGS ) Stubb Creek Field TEPN - Nkarika Field TOTAL - Egina Field Development TOTAL - OML 58 Upgrade Phase 1 TOTAL - OML 99 Ikike Field YFP - Aje Blk OML 113

Refining Oil

Oil Field Oil Field Development Floating Production (FPSO) Storage and Offloading Refinery Oil & Gas Field

3000000000 500000000

FEED EPC

Q2-2010 Q4-2008

Q4-2017 Q4-2014

Gas Offshore Oil, Offshore Oil, Offshore Gas

Liquefied Natural Gas (LNG) 20000000000 Offshore Platform 500000000 Oil Field Development Unknown Oil Field Development 1000000000 Gas Production 1000000000

EPC ITB EPC EPC EPC EPC

Q1-2005 Q2-2007 Q3-2006 Q1-2006 Q1-2011

Q1-2016 Q1-2014 Q4-2013 Q4-2014 Q1-2015

Oil Offshore Oil Oil, Offshore Offshore Offshore

Oil Field Development Offshore Platform Oil Field Development Oil & Gas Field Offshore Platform Offshore Platform

EPC EPC EPC ITB EPC EPC EPC

Q4-2003 Q1-2001 Q4-2003 Q1-2006 Q2-2009 Q4-2004

Q3-2012 Q4-2014 Q4-2015 Q2-2013 Q4-2015 Q4-2014

200000000 Unknown 2000000000 1000000000 Unknown 10000000

Project Summary Project Name

Ofon Field Development Phase 2

Name of Client

EPNL- Elf Petroleum Nigeria Ltd

Budget ($ US)

2,700,000,000

Award Date

Q4-2011

Facility Type

Offshore Platform

Status

EPC

Start Date

Q2-2007

End Date

Q1-2014

Location

Ofon, Nigeria

Project Backgrounds Nigerian National Petroleum Corporation and Total have launched Phase 2 of the Ofon Field Development Project.

Project Status In February 2012, Construction and installation works have been started. Eiffage Construction Metallique is constructing the platform from standard building blocks to be deployed in Oil Mining Lease 102, some 65km off the Nigerian coast, in water depths of 40 m. The platform will accommodate up to 140 personnel, generating around 45 m3/day tonnes of waste water per day. Engineering work will be done by Sofresid in Lorient and OOP in Lago. A consortium of Actemium Oil & Gas Engineering (AOGE) and Yokogawa was selected for providing the detailed engineering, functional analysis, HIPS detail studies, instrument data base management, supply of machines vibration monitoring system and electrical network power shading 5,000 I/O.

Nexans will provide Halogen free, thermoset compound SHF2 or XLPE low smoke PVC outer sheath to reduce gas flaring. The project is scheduled to come on stream in 2014. In August 2012, Wärtsilä Hamworthy was awarded a contract to supply sewage treatment facilities to the Eiffage to use on Ofon Field Development Phase 2. The ST50C treatment plant has been designed to operate within harsh offshore conditions in both a hot and humid salty environment, where it will also be subject to sand-laden winds. Incorporating pumps, blowers and instrumentation, the stainless steel unit will be designed, constructed and tested at Wärtsilä Hamworthy’s factory in Poole.

S11 ORA 5 2012 Technology A_Layout 1 02/10/2012 17:12 Page 57

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CONT CONTACT TACT A US U Tel: T el: e +973 1740 559 5590 90 Fax: +973 1740 5591 info@dmsglob info@dmsglobal.net bal.net www www.dmsprojects.net .dmsprojectts.net

S11 ORA 5 2012 Technology A_Layout 1 02/10/2012 17:12 Page 58

Logistics

Logistics remains one of the greatest tests oil companies face in Africa, especially in tough operating areas like the Niger Delta

Managing the

assembly line M

AKING AFRICA’S OIL industry tick is no easy business. From hauling giant offshore platforms across the oceans, to feeding the roughnecks on the rigs, supplying the oil and gas sector is a huge, often mind-boggling, task. In Nigeria, like other major oil-producing states, a vast team of contractors has been assembled to meet the industry’s diverse needs, whether that be catering, heavy lifting or power generation. In the Niger Delta region, that list also includes more prominent security. But despite all the complexities, the system works, facilitating a steady flow of new upstream projects including the multi-billion dollar development of mighty deepwater schemes, such as Nigeria’s Bonga field, led by Shell. This US$3.5bn scheme, which came onstream in 2005, became the country’s first major deepwater oil project, and a milestone for the thousands of contractors employed to make it happen. Further south, Angola’s rise to world oil prominence in the deepwater sector is in large part a testament to the finely-tuned logistics skills of the international oil companies (IOCs) and their highly sophisticated contracting teams. Here, Total, Chevron and other companies - like Shell - have become masters in managing the long logistics chain, a decisive factor in controlling the billion dollar budgets at stake. And increasingly this means deploying more local content in major upstream projects.

Kizomba triumph One of the more recent deepwater projects to come alive, this July, was the production start from the Kizomba Satellites Phase 1 offshore Angola’s Block 15, led by Esso Angola, a local unit of US supermajor ExxonMobil. It will ultimately produce 100,000 bpd from the Mavacola and Clochas fields, some 153 km off the coast, in water depths of 1,372 m. This project, completed ahead of schedule, entails the development of 18 wells with subsea tiebacks to the existing Kizomba A and B floating, production, storage and offloading (FPSO) vessels. Significantly, the development includes a high level of Angolan content, with approximately US$1.5bn invested in local goods and services. "Nearly 100 per cent of the topsides and subsea equipment were fabricated in Angola, and we have provided more than 10,000 hours of skill-based training to Angolan contractor personnel for the project," said Stephane de Mahieu, Esso Angola’s managing director.

58 Oil Review Africa Issue Five 2012

One of the more recent deepwater projects to come alive, this July, was the production start from the Kizomba Satellites Phase 1 offshore Angola’s Block 15. Seen here is the Kizomba B FPSO.

Despite all the complexities, the system works. Heavy loads Kizomba, like numerous other projects off Angola’s coast, shows just how far the deepwater logistics and services industry has come in this corner of the world. With many of Africa’s new and upcoming fields located hundreds of kilometres offshore, the challenges in putting together such complex projects are truly immense. But amid all the high-tech activity and intricate subsea work taking place - managed in no short measure by masses of computing power - it is easy to overlook perhaps the most spectacular aspect of this whole business, namely, scale. It is a sight to behold in the simple hauling of rigs and platforms to their ultimate destinations, using gargantuan heavy lift and transportation equipment from specialist contractors. It is an essential but little-reported service to the large oil and gas operators like Shell and others. One of the heaviest lifts yet in West Africa was provided by Saipem for ExxonMobil as part of its recent Yoho field development. The Italian contractor, part of the Eni group, lifted the 11,650 tonne deck module for the offshore Yoho field using the Saipem S7000 vessel, one of several heavy lifters in the company’s fleet. The entire module was raised and carried using

four super tough cable slings - each weighing approximately 42 tonnes - from steel ropes and moorings expert Franklin Offshore. This equipment is built to last, not only in terms of carrying the weight, but also in coping with tough environments such as rough seas and remote deepwater locations.

Local content Like Angola, recent years have seen greater pressure to employ local contractors in Nigeria to get the job done. This has meant an ever closer relationship for small indigenous firms working with the IOCs in all areas of the oil and gas chain. This year, Arco Marine and Oilfield Services Ltd, commenced delivery of fast passenger boats to French oil giant Total, part of a US$36mn order. At the launch of the first two boats, at Onne Port in Rivers State, Arco Marine’s managing director Yomi Jemibewon said his company had worked very closely with Total to complete the order. The boats will offer safe and secure transport to Total’s offshore platforms but will continue to deliver value to the country and its indigenization efforts going forward. “The boats are high-speed personnel carriers to be operated 100 per cent by Nigerians,” said Jemibewon. The final boats in the four-vessel contract are due for delivery early next year, he said.

Foreign expertise That does not mean expert foreign contractors are not still heavily engaged in meeting the industry’s

S11 ORA 5 2012 Technology A_Layout 1 02/10/2012 17:12 Page 59

Logistics hubs In the more developed oil centres, like Nigeria and Angola, the services and logistics industry is now well established, though this is not always the case in upcoming territories such as Ghana. Logistics experts like private UK-based firm Intels have also carved out a niche providing specialist ports

Logistics

diverse and complex needs. Wartsila Hamworthy, a UK unit of Finland’s Wartsila marine and energy group, recently bagged an order in Nigeria to supply a sewage treatment plant for an accommodation module on Total’s Ofon field second phase development. The stainless steel treatment plant is designed to operate in harsh offshore conditions in both a hot and humid salty environment, where it will also be subject to sand-laden winds. The Ofon II project consists of four new platforms: two production platforms, a processing platform and an accommodation platform. The accommodation module will sit 65 km offshore in water depths of 40 mm, with space for up to 140 personnel. The project will mainly recover offshore gas, to be compressed then shipped to shore. Wartsila Hamworthy has previously worked on two of Total’s other flagship offshore Nigerian developments, Akpo and Usan.

Valve maintenance on the Bonga FPSO.

and storage areas, and accommodation units, to bring together these diverse industry suppliers, from pipeline experts to IT services. It’s largest oil and gas logistics zone is located at Onne in Port Harcourt in Nigeria, a hub for much of the country’s offshore activity in recent years. The intention is to replicate the oil service centres that have sprung up in Aberdeen and Stavanger that supply the more mature North Sea region. Support services at Onne available include shipping and air freight; barges and tugs; dry docks; catering, diving and drilling expertise, among many others.

Combined with other providers, local and international, it is a set-up that has enabled places like Nigeria and Angola to create world-class oil and gas industries, despite the multiple and evercomplex challenges faced. With more African countries unearthing oil and gas - in West Africa, and now on the continent’s eastern flank, and inland - this expertise may well be in demand elsewhere. No matter how much gas is found off Mozambique, no matter how deep the water levels, the sophistication of the oil and gas industry’s logistics chain is up for the job. ■

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 Five 2012 59

S12 ORA 5 2012 Technology B_Layout 1 02/10/2012 15:39 Page 60

Technology

This article discusses the reliability of organic polymeric barrier coating technologies in mitigating and preventing corrosion under insulation compared to other options.*

Long-term coating solutions to

STOP CUI C

ORROSION UNDER INSULATION (CUI) is not a new problem, but it can be a serious one if it is not tackled on time. Commonly shared by the Oil and Gas Industry, CUI has caused major leaks which led to loss in production and health and safety incidents. Thus, the consequences of CUI can be expensive, accounting for as much as 60 per cent of a company’s static equipment maintenance costs. Taking place underneath the thermal insulation due to water ingress, CUI is a real threat for asset integrity. Therefore, asset owners are looking for cost-effective maintenance and repair options that can solve this unresolved problem.

A CUI profile CUI refers to the external corrosion of piping and vessels fabricated from low-alloy steels, carbon-manganese or austenitic stainless steels that occurs underneath thermal insulations due to water ingress. On stainless steel, CUI can cause induced stress corrosion cracking while on carbon steel corrosion manifests itself as generalised or localised wall loss. Common causes of water ingress are cladding or jacketing poorly installed, deterioration of the insulation over time and substrates lacking in protection, ie, barrier coatings. Along with the presence of water or moisture on the substrate, there are other conditions that accelerate the corrosion rate, these being the presence of contaminants either in the water, the insulation and/or the substrate and the operating temperature of the piping and vessels. The source of the contaminants can be external (ie, marine environments) or be produced by the leaching from the insulation material itself. However, high chloride contents of water can contribute to the appearance of one of the most dangerous types of corrosion in the industrial sector, which is chloride external stress corrosion cracking (Cl-ESCC) if operating temperatures exceed 60˚C (140˚F). With regards to the operating temperature of piping and vessels, there is different evidence to suggest that the temperature range should be between -4˚C (39˚F) and 175˚C (347˚F) for CUI to occur. However, the most critical temperature range identified has

60 Oil Review Africa Issue Five 2012

been between 30˚C (86˚F) and 120˚C (248˚F), as it is cited on the UK Health and Safety Executive (HSE) website. Along with the HSE, US data has indicated typical Fig 1. The mechanical ‘dove tail’ lock between the irregular corrosion rates of 0.5 mm/year at grit blasted surface profile and 100 per cent solids coating. temperatures of 80˚C (176˚F) under insulation for carbon manganese steels. Within the oil and gas Industry the most critical range has been identified by asset owners to be between 30˚C (86˚F) and 80˚C Fig 2. Heat Activated or Surface Tolerant coatings penetrate (176˚F). Though failures can occur over a the open steel substrate surface. wide range of temperatures, CUI will rarely solvent based asphaltic mineral fibre tapes and occur when equipment is operating conventional epoxy coatings, but none of continuously at temperatures above 150˚C these have proved to be infallible solutions. (302˚F); however there is increased risk during Another solution is the use of Thermal Spray periods of shutdown. Aluminium (TSA) in which a metal or organic The thermal insulation itself can contribute powder is melted and spray deposited on to a to the acceleration of corrosion rate by holding surface in order to provide protection. Some the moisture and any dissolved chemicals (i.e. drawbacks of TSA are that surfaces must be chlorides) on the surface even as the grit blasted and prepared until obtaining a Sa temperature increases. This situation creates 2 ½ profile. The surface preparation must be conditions that are more aggressive than those carried out during shut down periods which are associated with a typical marine atmosphere costly for asset owners as they must stop where typical corrosion rates are 0.1 mm/year. production. In addition, there is evidence that Some types of insulation are more susceptible suggests that TSA is failing in service when to trap moisture without letting it dry out exposed to prolonged periods of immersion. properly and others (i.e. those manufactured Another option to overcome CUI is the use with calcium and silicate) may contain of organic protective barrier coatings leachable chloride compounds. developed with the latest polymer technology As the effects of CUI are not visible and to protect the substrate. These types of organic can be highly localised, they can potentially coatings offer both a proactive and a reactive cause disastrous loss of containment and solution for CUI. They are reactive as once the equipment failure if they are not detected by problem appears it can be solved easily and inspection. Therefore, the prevention of CUI is proactive as they prevent the onset of CUI if the best way to reduce those risks. substrates of pipelines and vessels are lined. However, asset owners have requested a Thermal insulation itself can certain performance criteria to manufacturers contribute to the acceleration of organic linings for the development of protective barrier coatings to prevent CUI as of corrosion rate. they are essential to ensure plant production in the long-term. These requirements include the application of Polymer technologies for CUI the coating directly onto hot substrates with a In the market there are many options available minimal preparation of the surface. In addition, the for the prevention of CUI, the most common linings must resist aggressive partial immersion being the use of cladding to protect the environments, offer long-term corrosion resistance insulation from the external environment. and be safe and easy to apply. Moreover, However, main disadvantages of cladding are applications must be multi-coat with fast overcoat that these are prone to leakage at the joints times and solutions must be cost-effective. when poorly installed increasing the risk of With these criterias in mind, Belzona water ingress. Polymerics Ltd, a manufacturer of high There are other options such as surface performance solutions based on polymer treatment technologies like petrolatum tapes, technologies, designed a range of suitable

S12 ORA 5 2012 Technology B_Layout 1 02/10/2012 15:39 Page 61

Your Partner... ...For Power

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S12 ORA 5 2012 Technology B_Layout 1 02/10/2012 15:39 Page 62

products for CUI. Main features of the Belzona Solutions for CUI are that these can be applied in-situ onto minimally prepared metal substrates. Surface preparation can be done using a simple application technique, ie, with a wire brush. This way of preparing the surface eliminates the need to grit blast and the additional costs and safety complications of carrying out this procedure such as, environmental control, creation of a habitat (confined space), contamination of the surrounding area, spark risks, among others. Another important characteristic of the Belzona Solutions for CUI is that they have heat activated curing properties which

generate suitable adhesion on the substrate. Adhesion on the substrate is generated thanks to the opportunities that a hot corroded steel substrate presents as porosity of the steel increases with the heat. Therefore, in this situation the coating is capable of penetrating in to the substrates surface granular structure after minimal surface preparation and creates a similar mechanical lock to the one acquired by grit blasting. In addition, once the coating gets in contact with surfaces between 30˚C (86˚F) and 150˚C (302˚F), the 100 per cent solids coating viscosity reduces and it penetrates the substrate even more before curing and creating the mechanical bond. Figures 1 and 2 illustrate this idea.

Fig 5. Completed application

Case study: UK refinery condensate vessel protected against CUI

Fig 3. Surface preparation

Fig 4. Brush application

In June 2001, a severe CUI problem was detected in a condensate vessel which operates at 85˚C (185˚F) during a routine inspection. The corrosion, if left untreated, could have caused considerable damage. Therefore, a suitable solution which did not interrupt operations was required by the asset owner. The refinery opted for an on-line solution using a mono component; heat activated organic barrier coating Belzona 5851-HA Barrier due to operation and surface preparation requirements. Therefore, the surface was prepared to a St3 (SSPC SP3) standard using power tools and loose surface rust was removed by power wire brushing. The surface was then cleaned and de-greased. The surface temperatures of the vessel ranged between 50 ˚C (122 ˚F) and 110 ˚C (230 ˚F) at the top and due to the requirement of a minimum temperature for the application of the heat activated product, the coating was applied by brush down two thirds of the vessel. The second coat was then applied after the first coat cured. The application was completed in four hours and the product fully cured

Fig 6. Condition of the coating in 2002 after being inspected

within three hours. In February 2002, an initial inspection was carried out after several months of continual operations of the vessel. When sections of the insulation were cut away to inspect the condition of the coating, it was found in good condition. Later on in 2008 and 2011 other inspections were done, and they confirmed that the original application still remained in good condition after ten years in service. ■

* Adriana García, Marketing Executive-Oil and Gas, Petrochemical and Bulk Chemicals, Belzona Polymerics Ltd.

Expanded pipeline coatings portfolio AS PART OF its continuing efforts to address the growing needs and demands of the region’s oil and gas segment and general pipeline industries, Jotun Powder Coatings has revealed a strategic move to expand its current pipeline coatings portolio. To bolster this move, the company has combined its powder and liquid coatings to create and develop a new extensive range of pipeline coating solutions; providing transmission pipelines with the requjired protection - both inside and out. The move complements Jotun’s efforst to increase its regional market share over the next three years. The move also aims to create a one-stop shop for Jotun’s customers and provide a single point of contact to meet the unique pipeline coating needs of oil and gas companies and pipeline applicators - making the entire process smoother, more efficient, quicker and more economical. To date, Jotun currently enjoys a 30 per cent market share of the Middle East pipeline coatings market and plans to

62 Oil Review Africa Issue Five 2012

significantly increase its presence over the next three years. Jotun is widely recognised as a leading pipeline coating solutions provider; protecting more than 100,000-km of pipelines over the last 30 years. “Combining both liquid and powder coatings to create a new range of pipline coating solutions that provide the best protection inside and out is in line with our move towards achieving an increased presence in the region’s pipeline coatings segment,” said Andrea Meconcelli, Global Commercial Director for Functional and Architectural - Jotun Powder Coatings and the Global Concept Manager for Jotun Pipeline Solutions. “Our dedication towards the research and developments of improved powder and liquid coating solutions has placed us at the forefront of the coatings industry. Jotun will continue to remain steadfast in its commitment to meet the demands of our growing customer base by offering a more streamlined supply chain covering all stages - from quotation to delivery.”

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Technology

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A combination of ageing plants, greater fluid corrosiveness and tightening of HSSE requirements has made corrosion management a key consideration for oil and gas companies. Peter Collins* reports on an innovative continuous monitoring system used to mitigate corrosion.

A step change in

corrosion monitoring C

ONTINUOUS MONITORING PROVIDES asset and integrity managers with an up-to-date picture of how their infrastructure is coping with the demands placed upon it. This information informs decision making about maintenance and replacement, optimisation of prevention/mitigation strategies, and feedstocks. Continuous measurement presents a step change in the levels of corrosion rates that can be determined and the accuracy of that determination.

Plant integrity Steel pipework and vessels are always at risk of corrosion or erosion. Unless monitored there is a risk of failure which may impact the safety of workers and the environment, quite apart from the financial costs of operational interruption, of repairs and of reputational damage. As oil and gas operators produce and process ever more corrosive or erosive hydrocarbon streams the demands on plant metallurgy steadily increase. Permanently installed sensor systems deliver a continuous picture of asset condition over time, at a comparable cost to that of a single manual inspection. This picture can be correlated with process conditions that may be causing corrosion or erosion, and with strategies to minimise corrosion such as inhibitor use, enabling the asset manager to move beyond merely knowing whether corrosion or erosion is occurring to understanding why and at what rate. This understanding enables operators to make better-informed decisions.

The need for continuous monitoring There are various established techniques for the periodic assessment of pipe and vessel integrity. However periodic inspections do not deliver continuous pipework condition data that can be correlated with either corrosion and erosion drivers - process conditions, crude constituents and abrasive solids - or inhibitor use to enable understanding of the impact of process decisions and inhibitor strategy on plant integrity. Manual acquisition of ultrasonic wall thickness data is also frequently associated with repeatability limitations and data logging errors. Permanently installed sensor systems on the other hand deliver continuous high quality data. Permasense has developed an ultrasonic sensor that can be installed on pipes/vessels operating at up to 600째C. This sensor has been certified as intrinsically safe for use in the most hazardous of environments, and is proven in operation over a

64 Oil Review Africa Issue Five 2012

number of years in refinery environments, and more recently in upstream facilities. Permanent installations show that where corrosion is taking place it is often intermittent rather than continuous. In such cases it is particularly valuable to be able to correlate thickness data over time with process and/or inhibitor parameters. Moreover, the data highlights which prevention or mitigation strategies are most effective.

Permanently installed sensor systems deliver a continuous picture of asset condition over time, at a comparable cost to that of a single manual inspection. System design At the core of the Permasense system is an ultrasonic sensor mounted on stainless steel waveguides (figure 1). The waveguides isolate the sensor electronics from extreme temperatures and guide the ultrasonic signals to the pipe wall and back without excessive signal degradation and distortion. The system can monitor pipe wall thicknesses of over three mm in a wide range of steels and other alloys. The frequent measurement of corrosion allows for metal loss detection at the level of tens of microns. Each sensor is equipped with a radio and communicates with other sensors and a gateway (base station) within a 50m range. The sensors form an independent mesh or wireless network (figure 2) and each sensor radio can act as a relay,

Figure 1: The Permasense sensor.

or repeater, enabling the network to span hundreds of metres from the gateway. Data is channelled via the gateway to a database on a connected computer. If, as is usual, this computer is networked, browser-based visualisation software enables the corrosion/inspection engineer to view the data at their desk. The data can also be exported in any of the file formats required by the various process monitoring applications, enabling

Figure 2. The Permasense system.

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Technology

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seamless transfer and read-in to those packages and thus correlation with the process data at the sensor location.

Cost effective for large scale deployment All Permasense sensors are battery powered meaning no cabling is required. This minimises installation costs and enables use in remote areas and on a large scale. The sensor is secured on the pipe/vessel by means of two studs which are welded onto the pipe. For pipe wall temperatures below 100°C the studs can also be welded onto girth clamps, themselves mounted on the pipe. Stud mounting allows for dry coupling - no couplant is required between the waveguide tip and the pipe wall. This, together with multi-year battery life, eliminates the need for expensive maintenance access between turnarounds. Stud-based mounting also enables geometric flexibility and reduces installation time to just minutes; a two-man installation team can typically install 50 sensors per day.

Continuous monitoring on near-end-of-life lines enables turnarounds to be scheduled with much greater confidence. Robust wireless network communication The sensor has been designed using high-grade materials to allow for many years of continuous operation, and a number of systems have been in uninterrupted operation for four years. To ensure the system performs in the event of a blockage of an individual pathway, or the loss of a sensor, there are multiple pathways for data transmission through the mesh back to the gateway (Figure 2) to ensure data retrieval. The gateway channels data transmitted from all the sensors located in the network. Typically wall thickness measurements are sent every 12 hours; but this interval can be changed at any time for any sensor, to as little as every few minutes if necessary, depending on the monitoring or metal loss determination requirement at that location. Data is stored in the computer database to guarantee security and this allows the user to view a full history of data readings helping to build up a clearer picture of corrosion and erosion rates.

Applications The system has a wide range of applications in oil and gas and petrochemical facilities. To date in refineries, for example, these include virtually all crude unit lines, air coolers, furnaces, heat exchangers, pumps, amine units, cokers and cracking units. Upstream, systems are in service in central processing facilities and feeder lines in onshore production, on offshore gas production platforms and in LNG plant. Pipe materials include carbon, chrome and stainless steel. Typical locations for sensor installation are on elbows, known thin spots, and areas of particular turbulence. Older units, particularly those operating outside of design specification, are particularly worthy of attention. The system allows facility operators to monitor locations continuously without the repeated cost of access, and for little more than the cost of a single manual inspection. Continuous measurement presents a step change in the levels of corrosion rates that can be determined and the accuracy of that determination. By correlating metal loss data with process data (composition, hold-up, temperature for example) a true understanding can be gained of what changes in what parameters are driving corrosion and erosion. The system enables operators to make betterinformed decisions about changes according to these parameters to minimise impact on their plant. Furthermore, users are now optimising their inhibitor strategies through the insights gained from the data. Continuous monitoring on near-end-of-life lines enables turnarounds to be scheduled with much greater confidence. In a recent example, a system installed on a line with an expected remaining life of 12 months enabled line replacement to be postponed by a very valuable six months.

Inspector safety In plants with aggressive rates of corrosion, particularly where the corrosion is intermittent and the remaining life is uncertain, frequent manual inspection is common. If a shutdown is necessary to enable manual inspection (because of high operating temperatures or for safety reasons for example) the loss of throughput can come at a high cost. Some locations in a facility can be hard to reach, meaning technicians incur safety risks in gaining access. Where high pipework/vessel temperatures are involved ensuring technician safety during manual inspection becomes even more challenging.

Figure 3 - Measured wall thickness for sensors installed on one carbon cast steel U-bend.

66 Oil Review Africa Issue Five 2012

Permanently installed systems reduce the safety risks associated with collection of plant condition data. In several facilities Permasense system users have also been able to eliminate the periodic shutdowns previously required to enable operator access at high pipework temperature. The installed systems are also now delivering data where inspector availability is limited or access is difficult for environmental reasons.

Gelsenkirchen experience Corrosion monitoring was conducted on cast carbon steel u-bends with a wall thickness of approx. 25mm (1in.), operating at 380°C (720°F) in the Gelsenkirchen refinery operated by BP to ensure continued safe operation (figure 3). Because the high temperature prevented accurate manual ultrasonic wall thickness measurement, and would have exposed inspectors to significant hazard, the Permasense continuous monitoring system was installed (figure 4): this secured operation with confidence until turnaround. The system has been delivering reliable measurement data for over three years now.

Figure 4. Carbon steel u-bend with Permasense sensor.

Conclusion Operators using the Permasense solution for continuous corrosion monitoring have a more accurate and timely understanding of the corrosion and erosion rates occurring in their facility. Where inhibitors are in use the system is giving a greater understanding of their effectiveness. The continuous provision of data allows potential corrosion hotspots to be remotely monitored in real time and at time intervals of the operator’s choosing, as frequently as every few minutes if necessary. This insight allows asset managers to make more informed decisions to the benefit of plant integrity, safety and operating costs. The system has been tried and tested in some of the most inhospitable environments and operates at pipework temperatures running at up to +600°C. It allows operators the freedom to choose monitoring locations irrespective of how inaccessible they are thanks to the use of ultrasonic sensors and wireless networks for data retrieval. The system has been deployed in refineries and upstream facilities, including offshore platforms, worldwide. The experience of 11 oil companies operating the system has proved that the data it generates enables significantly better informed decision making in managing their assets. ■

Peter Collins, CEO of Permasense Ltd, UK

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Technology

Deeper wells and renewed safety concerns pose new challenges for the offshore oil and gas industry. Providing solutions offers both opportunities and rewards.

Deep well challenges;

the hunt for black gold D

ESPITE MOVES TOWARD greater energy efficiency and a turbulent economic climate, global demand for oil and gas shows no sign of letting up. Consumption in the developed world may be flatlining, but China will more than double its oil consumption from 2000 to 2015, while in India demand will increase by about 75 per cent. Debate continues about when “peak oil” will be reached, but the fact remains that a huge amount of oil is still in the ground – enough to last several decades by most estimates. The problem is that much of the “easy” oil has been found, and demand for energy is taking exploration and production to ever-tougher extremes of geography and climate. The deepwater (more than 500 m and ultra-deepwater (more than 1,500 m) energy sector represents one of the major growth areas for the oil and gas industry, but exploiting these reserves presents tough technical challenges. “This is a very onerous environment,” says John Drury, Business Group Director for Trelleborg’s business that focuses on the offshore industry. “The risks multiply exponentially with depth, and operators are looking for fail-safe solutions.” One issue with ever-deeper wells is that the hot oil cools and thickens on its way to the surface, slowing the flow and potentially causing blockages. One of Trelleborg’s many product lines for the oil and gas industry is thermal insulation material to prevent this cooling. “Our materials are engineered to cope with environments at extreme depth plus temperatures well in excess of 100°C,” says Drury. Safety has long been a priority for the offshore oil and gas industry, but the Deepwater Horizon explosion in the Gulf of Mexico, which resulted in 11 deaths and the largest accidental oil spill in history, thrust the issue into the spotlight. “Operators are introducing increased riskmitigation strategies to avoid these sorts of incidents in the future,” says Drury. “There should be further opportunities for our safety-related products as legislation is introduced.” Among Trelleborg’s wide range of safety systems for the offshore oil and gas industry are the Elastopipe deluge system for fire protection, microspheres for smothering fires and flexible fireretardant coatings. Trelleborg is also working on innovative buoyancy solutions that improve safety by reducing the load on the long pipes bringing oil up more than a kilometer from the seabed. The industry, which accounts for about 10 per cent of Trelleborg’s total sales, has witnessed

68 Oil Review Africa Issue Five 2012

Trelleborg O-rings.

One issue with ever-deeper wells is that the hot oil cools and thickens on its way to the surface. increased globalisation in recent years as new deepwater fields are exploited, such as off the coast of Vietnam, Brazil and West Africa. “In Brazil there is heavy investment to enable the construction of ships in the country, whereas historically they might have been built in Korea,” says Drury. “Similarly in Southeast Asia there is a shift toward deeper waters, and at the same time countries in the region are looking to develop more locally based supply chains.” To capture these opportunities, suppliers including Trelleborg are setting up production in these new markets.

Competition tougher than ever But while the opportunities are plentiful, the competition is tougher than ever. “There are a lot of building projects ongoing, but people are being very aggressive to win and everyone is very conscious about margins,” says Thor Hegg Eriksen, Business Unit President for Trelleborg’s business that focuses on the offshore industry. “This seems a bit of an anomaly for a

business that is making so much money on the operator side. But there is not really a direct competitor that is able to offer such a broad product portfolio from as many locations as Trelleborg.” Industry observers see an intriguing period ahead, with expected regulatory changes on safety, national oil companies becoming more outward looking, the rise of Asia as a supplier and consumer, and increased investment in deepwater drilling. “There are changes going on, and it is an interesting environment,” says Eriksen. “But with our core competencies, our ability to work on a global scale and our extensive innovation work, Trelleborg is well positioned to see what happens and to jump on the opportunities as they arise.”

On the rise With the deepwater discoveries off its Atlantic coast representing a third of all worldwide oil discoveries in the past five years, Brazil is widely touted as the next oil giant. Petrobras, which has grown to become the world’s third-largest oil and gas company by market capitalization, will be investing some US$224bn by 2014, much of it in platforms, rigs and other infrastructure. To supply this booming market, Trelleborg is investing heavily in Brazil, acquiring an existing factory and building another on a greenfield site. “Brazil is becoming hugely important,” says Brian McSharry, President of Trelleborg’s U.S. business

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essential. www.marellimotori.com

Technology

S13 ORA 5 2012 Technology C_Layout 1 02/10/2012 15:35 Page 70

that focuses on the offshore industry. “We have studied the market conditions and recognised the significant potential, and as a result we have established a major presence there.” The new facility, located in Brazil’s oil capital, Macaé, will manufacture a wide range of polymerbased solutions for offshore topside and subsea oil and gas exploration. “There is no other manufacturing on this scale in the country,” says McSharry. “We will be able to reach near capacity relatively quickly, and the size of the facility is such that if we need to expand, we can.” The second factory, at Santana de Parnaiba, was acquired in April 2011, together with a nipple hose technology for transferring oil from floating production, storage and offloading vessels and terminals. “This product completes our product and solution portfolio,” says Managing Director XavierAlexandre Delineau. Another line at the factory will produce printing blankets to cater to the growing Latin American printing market. Petrobras has set aggressive objectives on local content for its projects, so the factories are important for Trelleborg to access Brazil’s oil and gas market. “One of our goals is to have two worldclass factories serving the global offshore and marine offloading business, and we have a plan in place to sustain and develop our leadership position,” Delineau says.

Avoiding explosive decompression failure When engineers specify a seal material for an application, they have to consider such things as working temperatures, pressure and compatibility with chemicals. In oil and gas applications there are other critical criteria that must be considered, such as explosive decompression. Inherently, elastomer seals contain voids. Gas or gas mixtures in contact with elastomer surfaces during oil and gas processing are absorbed and saturate elastomer seals. At high pressure this absorbed gas is in a compressed state. When external system pressure is reduced, either rapidly or over a relatively short period of time, the compressed gas nucleates, inflating at the voids within the elastomer. Depending on the strength and hardness of the elastomer, this can cause the elastomer to break or crack. No elastomer can be completely ED resistant. However, Trelleborg has engineered the XploR™ range of sealing materials that demonstrates unrivaled ED resistance for each elastomer type.

An innovative system Trelleborg has developed a new stackable version of its innovative RiserGuard® system that provides a solution for rigs with limited storage space while offering the same high protection as the original system. “We originally developed our RiserGuard

Trelleborg has developed a new stackable version of its innovative RiserGuard system that provides a solution for rigs with limited storage space.

product to help protect bare riser joints as they were handled and run on the rig,” says Alan McBride, Vice President of Drilling at Trelleborg’s business that focuses on the offshore industry. “In addition, the product would enable the riser to be run and pulled quicker, saving valuable rig time.” The new joints can be stacked alongside buoyant riser joints in the same deck storage area, thanks to strategically placed protective sections spaced within the RiserGuard that transfer loads between the joints and the deck. “Always keen to meet the changing wants and needs of our customers, we recognised the need to be able to stack the riser joints and decided to develop a stackable version of the product,” McBride says. ■

www.trelleborg.com

Umbilical tubing withstands harsh subsea environments

tel: fax: mobile: email: web:

+218 (0) 21 361 01 73 ext 200 +218 (0) 21 361 82 80 +218 (0) 92 747 53 70 res@budgetlibya.com www.budgetlibya.com

70 Oil Review Africa Issue Five 2012

RATHGIBSON, A LEADING manufacturer of welded, welded and drawn, and seamless stainless steel, nickel, and specialty alloy tubing, produces umbilical tubing with enhanced tensile strength and corrosion resistance for a wide range of operating temperatures and pressures. The increasing water depths and higher working pressures make subsea an extremely harsh environment. RathGibson offers laser-welded Lean Duplex 19D, a cost-efficient alternative for subsea umbilical applications. Zinc cladding is added for improved external protection against corrosive-inducing, temperaturefluctuating subsea conditions. RathGibson's zinc clad Lean Duplex 19D tubing undergoes extensive quality testing, including x-ray, eddy current, ultrasonic, and final acceptance testing (FAT) to meet and exceed ASTMA789 and ASTM-A790 specifications. Since 2001, RathGibson has placed over 6,500 km of its zinc clad lean duplex welded tubing in dynamic and static subsea umbilical applications. The company's umbilical tubing is currently installed in waters up to 2.3 km in depth and lengths up to 52.3 km. Stated John Sinks, Vice President — International Sales, “RathGibson’s umbilical tubing for the subsea industry is precisely engineered for various applications, such as control lines, flying leads, electrical lines, chemical injection lines, and hydraulic lines." RathGibson's umbilical tubing complements the offshore product portfolio provided by parent company, The PCC Energy Group, a member of the Precision Castparts Corp. The PCC Energy Group provides raw material and components integral to Oil Country Tubular Goods (OCTG) products, blowout preventers (BOPs), high pressure/high temperature (HP/HT) pressure control equipment, manifolds, splash zone piping, and risers and flexjoints. RathGibson, a PCC Energy Group Company, is a worldwide manufacturer of precision engineered straight ngths, coil, and U-Bend tubing for diverse industries such as power generation, renewable, oil and gas, petrochemical, chemical, food and dairy, beverage, pharmaceutical, and general commercial.

S14 ORA 5 2012 Technology D_Layout 1 02/10/2012 17:38 Page 71

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S14 ORA 5 2012 Technology D_Layout 1 02/10/2012 17:38 Page 72

Technology

Disposing of the unwanted elements brought to the surface during oil and gas production - primarily sand and water (at times gas) - can present a challenge, particularly as the waste water can contain small traces of potentially harmful hydrocarbons.

Understanding

subsea separation W

ITH THE ADVENT of subsea processing the oil, gas, sand and water emerging from the well are separated at the sea-bed with only the useful oil and gas elements being transported to the surface. The bulk of the waste components can be ‘reinjected’ into the reservoir, boosting the reservoir pressure, giving a faster production rate. The re-injection process can also dramatically increase the percentage of oil and gas that can be recovered from a given reserve.

Subsea processing functions Subsea processing can encompass a number of different processes to help reduce the cost and complexity of developing an offshore field. The main types of subsea processing include subsea water removal and re-injection or disposal, single-phase and multi-phase boosting of well fluids, sand and solid separation, gas/liquid separation and boosting, and gas treatment and compression. There are a number of reasons why operators may choose to install subsea processing equipment. First of all, most subsea processing will increase the recovery from the field, thus increasing profits. Additionally, by enhancing the efficiency of flowlines and risers, subsea processing contributes to flow management and assurance. Also, subsea processing enables development of challenging subsea fields, while reducing topside expenditures for equipment. Furthermore, subsea processing converts marginal fields into economically viable developments. Shell's BC-10 project offshore Brazil was the world's first subsea system with gas/liquid separation and boosting. Developed via 13 subsea wells, six subsea separators and boosters, and an FPSO, the BC-10 project began producing heavy oil from ultra-deepwaters in July 2009.

Advantages and challenges of subsea separation Subsea separation is used to avoid topside separation facilities, thereby reducing topside structure and payload requirements, to remove water from the production stream, or to separate gas from liquid subsea. It further reduces the amount of production transferred from the seafloor to the water's surface, debottlenecking the processing capacity of the development. Also, by separating unwanted components from the production on the seafloor, flow lines and risers are not lifting these ingredients to the facility on the water's surface just to direct them back to the seafloor for re-injection. Re-injection of produced gas, water and waste increases pressure within the reservoir that has been depleted by production. It also helps to decrease unwanted waste, such as flaring, by using the separated components to boost recovery. Additionally subsea boosting negates backpressure that is applied to the wells, providing the pressure needed from the reservoir to transfer production to the sea surface. From the subsea separation challenges standpoint, while there is a distinct need for simplicity of use and maintenance in all subsea equipment, the use of equipment like compressors, pumps and control valves, either single phase or multiphase, at the sea floor offers challenges for performance, reliability and maintenance. A long subsea tie-back and a deeper water depth would require longer umbilicals, which, in turn, would require the use of larger electrical power supplies on the surface or the production platform due to the greater amount of power losses sustained over longer distances. While the space required on board a platform for the processing equipment is reduced, there is a greater need for more space just to house the power supplies. This can mitigate the advantages of having a reduced footprint for the processing equipment. Another disadvantage to using subsea processing equipment is the

72 Oil Review Africa Issue Five 2012

Figure 1. Subsea processing facilities (photo courtesy Prescott, 2012).

Subsea processing can encompass a number of different processes to help reduce the cost and complexity of developing an offshore field. maintenance cost and the expenses for intervention should a failure (due to sand production etc) or leak occur. In most cases, production will have to be shut down and expensive repair jobs carried out or in some extreme cases, it might be found more efficient to replace the failed equipment or in some cases, based on cost studies, there might be reason to provide a backup system in place for all subsea equipment.

Subsea separation technologies Subsea separation technologies involves separation either in two phase or three phase. 1. Two-phase (gas-liquid or liquid-liquid) Gas-liquid separation: Subsea gas-liquid separation is one of the alternatives to multiphase boosting to extend the distances of multiphase transportation. The development of offshore gas and oil reserves continues to move into deeper waters and marginal fields. The economics of many of these fields do not justify the use of fixed leg platforms or of floating production facilities. After separation, the liquid phase is typically pumped to the surface facility to enable higher efficiency pumping, minimise flow assurance risks, overcome the hydraulic head of the water column or diminish tie-back limitations. Typically the gas phase free flows to the surface facility. In all cases the back pressure on the wells and reservoir can be significantly reduced, thereby increasing production and reserves, and also minimising operational flow assurance issues such as hydrate formation and slugging. It’s also effective in enabling the production of complex reservoirs containing heavy, viscous oil and low pressures. This approach has been successfully applied in Shell’s Perdido and Parque das Conchas (a.k.a. BC-10) projects and Total’s Pazflor.

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Technology

S14 ORA 5 2012 Technology D_Layout 1 03/10/2012 10:32 Page 74

Below are a few benefits of subsea gas-liquid separation when it is combined with pumping of the liquid phase to one line and natural flow of gas in a separate riser; 6 There is a low pressure drop in the gas line, this has the advantage of eliminating the compressor topsides. 6 Low erosion velocity for the top of the riser due to low gas velocity. 6 Reduced hydrate risk because of the possibility to decompress the separator and deep water flowline through the gas riser. 6 Easier restart of wells by lowering separator pressure. 6 Possibility of using a standard centrifugal pump to lift the liquid. Liquid-liquid separation: the water phase is typically pumped either into a disposal formation as in Statoil’s Tordis project or back into the producing reservoir (which increases reservoir sweep and recovery) similar to Petrobras’ Marlim project. Either approach lightens the produced fluids column and reduces the backpressure on the wells and reservoir. The gas and oil phase can be flowed naturally to surface or pumped, either separately or comingled back together. The separation technologies employed have been gravity based (which employs gravity to separate the phases) or cyclonic (which employs spin and centrifugal forces to enhance the separation between phases). 2. Three-phase (gas-liquid-water) Subsea three phase separators are used to separate gas, oil and water phases. Three phase separation involves gas/liquid separation like two phase, and also involves liquid/liquid separation (water and oil). It is used to optimise gas separation using the gas for re-injection purposes and for water flooding enhanced oil recovery. It also increases oil production. The basic design aspects of three phase separation are identical to those discussed for two phase separation. The only additions are that more concern is placed on liquid-liquid settling rates, and that some means of removing the free water shall be added.

® WORLDWIDE LEVEL AND FLOW SOLUTIONS

Figure 2. This FMC graphic of the Statoil Tordis field separation and boosting module depicts gas/liquid separation, oil/ water separation, multi-phase pumping, water injection pumping and the separation of solids (photo courtesy of Intech Engineering, 2007)

There are a few benefits of subsea glass-liquid separation when it is combined with pumping of the liquid phase to one line and natural flow of gas in a separate riser. Some three phase separators are called free water knockouts. They are designed to separate the free water phase from the oil. Flow to the separator may be directly from a producing well. In this case, significant amounts of gas may be present and the separator will typically be called a three phase separator.

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Subsea processing and separation requires remote actuation of its process control valves controlling fluid switching and control of flow-rate and pressure. Usually, these valves have been remotely actuated by means of a high pressure hydraulic system. A major drawback with hydraulic actuation is the complexity, inefficiency and cost of the hydraulic power supply system. Usually located at the surface, the hydraulic supply can be situated up to 100+ km remote from the subsea installation. Inherent in this approach is the use of two custom designed hydraulic hoses for both high pressure supply and low pressure return. These hoses represent a major infrastructure investment causing power losses and are potentially vulnerable to damage. On the other hand, electric actuation technology though in its infancy, looks to dominate the market in the future because of some key advantages, namely: Firstly, the reduced cost of an electrical rather than hydraulic umbilical. This is particularly relevant to installations with large â&#x20AC;&#x2DC;step-outsâ&#x20AC;&#x2122; (horizontal pipeline distances between the well and the surface). If the electrical power is transmitted at high voltages and low currents then relatively compact cables can be used. Secondly, there is reduced environmental impact, particularly when compared with a single hose, total-loss hydraulic system.

Electric actuation technology looks to dominate the market in the future. Conclusion One of the key requirements for successful subsea equipment use is extreme reliability, as maintenance is very difficult and prohibitively expensive. Finally, in order to influence the choice of separation system below are key considerations: 6 How will separated streams be handled?

Technology

Subsea actuation technology: hydraulic or electric?

The Pazflor development plan is strikingly innovative, based largely on the installation of separation and pumping units on the seabed.

6 6 6 6 6 6

Is there sufficient physical room to install the required separation equipment? Do we expect sand or solids in the flowstream? How about other impurities? Are foaming and corrosive tendencies likely to occur? Are there waste products to be disposed of? What of these elements or others are likely to impact flow assurance? Do we expect liquid slugging or surging?

Chikezie Nwaoha (AMIMechE, MOSHAN) is an independent researcher and a graduate of Petroleum Engineering (with specialty in process engineering. â&#x2013;

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FOCUSED LEVEL MEASUREMENT European Headquarter and Manufacturing Heikensstraat 6 9240 Zele, Belgium Phone: +32 (0)52 45 11 11 Fax: +32 (0)52 45 09 93 e-mail: info@magnetrol.be www.magnetrol.com

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New generation semi-submersible vessel changing the game

Future of exceptional

heavy marine transport I

T’S NOT EVERY year a new vessel is recognised as a true game-changer. The anticipated Dockwise Vanguard has been designed to enable operators and contractors to consider opportunities for mega offshore units which were, until now, considered unthinkable. The Dutch marine contractor Dockwise’s new generation vessel—currently under construction—will enter the heavy marine transport market with anticipation.

Next generation requirements The next decade is expected to see a growing demand for transportation and installation projects, particularly for the transport of integrated offshore units to remote locations. Today, these fully integrated offshore units such as TLPs and semisubmersibles are currently transported separately. Other units, such as spar buoys and FPSOs, can only be transported up to a certain size and are usually wet-towed to their destination. Existing semisubmersible heavy-lift vessels can’t transport the next generation of platforms. The world’s current largest semisubmersible heavylift vessel, the Blue Marlin—also owned by Dockwise—can carry structures of up to 76,000 metric tons. While capable of transporting some mega structures (such as BP’s Thunder Horse), the Blue Marlin is limited in its ability to transport larger and heavier units. Many of these newer units require a new type of vessel with a significantly increased carrying capacity along with an increased deck size and flexibility.

The Dockwise Vanguard’s capabilities present new opportunities which were unthinkable until now. 76 Oil Review Africa Issue Five 2012

In light of next generation requirements, Dockwise decided to invest in a completely new vessel capable to transport super-sized offshore structures.

Innovative design The Dockwise Vanguard was engineered to surpass current heavy marine transport limitations. The vessel’s accommodation block and navigation bridge are located on the extreme starboard side. The vessel has no bow, and this, along with other design features, gives the vessel a unique appearance. Furthermore, the deck covers a surface of 275 m by 70 m, equipped with movable casings suitable for overhang in all directions. In addition, the vessel has a dedicated design for ultra-heavy units weighing up to 110,000 metric tons. Optimised deck strength and extreme wideload capabilities are at the heart of the design philosophy; as are the vessel’s stability characteristics. It is equipped with a 27 MW redundant propulsion system consisting of two fixed propellers at the aft and two retractable azimuth thrusters at the bow. These can reach a maximum transit speed of 14 knots, which translates to average service speeds of 11-13 knots with cargo. In addition, the vessel allows for 16 meters water above deck, accommodating cargoes with a higher draft.

New opportunities The Dockwise Vanguard’s capabilities present new opportunities which were unthinkable until now. Companies in the oil and gas industry can now specify much larger and heavier offshore structures, and these can be integrated at a single fabrication site. These mega structures can then be transported onboard the vessel to remote offshore locations, even in harsh climates where no commissioning facilities are available. This feature can help reduce

costs and optimise the overall project. In essence, the new vessel will play an important role in the field development philosophy of oil and gas majors, since it will be capable of transporting fully integrated mega offshore units. The vessel’s design is also expected to help operators and developers create value. With its capabilities, timely and risky phases of offshore projects can be managed prior to hookup and commissioning. Interface optimisation, higher degree of risk mitigation, lower insurance premiums, improved schedule flexibility, and reduced time-to-production – as well as reduced

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Offshore dry-docking Increasingly, FPSOs are being located in remote areas which lack support infrastructure. In this circumstance, an offshore dry-docking service can be specially valuable. The Dockwise Vanguard’s FPSO dry-docking capacity offers inspection, maintenance, and repair opportunities (amongst others) at different conditional modes. The FPSO could remain connected to its mooring and turret system while keeping the riser systems intact, with the possibility of continuing limited production. In this scenario, the FPSO will still be able to freely weathervane around the turret mooring, with controlled heading made possible by the vessel’s propulsion system. In order to fully realise this new offshore service, Dockwise received an “approval in principle” from ABS following the commissioning of a hazard identification (HAZID) safety assessment. This assessment took place in the presence of a multidisciplinary team of experts and representatives from two oil and gas majors.

type platform—from Hyundai Heavy Industries to the Eni Norge Goliat Field in the Barents Sea. The third assignment consists of transporting a 45,000 ton spar buoy for Statoil. The platform, measuring approximately 200 m in length with a 50 m diameter, will be transported from either Korea or Finland—subject of yard choice—to Aasta Hansteen (ex Luva) field in the Vøring area. The vessel’s design philosophy received two awards by maritime organisations. The first award was from the Royal Association of Dutch Ship Owners for the KVNR Shipping Award 2011. This award recognised the Dockwise Vanguard as the

most innovative vessel. The second recognition, an OTC Spotlight on New Technology Award bestowed at this year’s conference, also recognised the vessel’s innovative design. In selecting a new technology winner, the jury’s decision was based on the following criteria: new, innovative, proven, broad interest, and significant impact. With its innovative design, the Dockwise Vanguard symbolises the future of exceptional heavy marine transport. This next generation vessel is uniquely capable to offer a new world of opportunities. ■

Industry Anticipation The Dockwise Vanguard continues to capture the interest of oil and gas majors. Three contracts have been agreed, each transporting behemoth sized platforms. The maiden assignment will load and transport Chevron’s Jack/St.Malo 50,000 ton semisubmersible hub production facility from the Samsung yard to Kiewit’s Corpus Christi facility in the US Golf Coast. Upon completion, it will return to Korea for its second assignment to transport Eni’s Goliath FPSO—52,000 ton cylindrical Sevan-

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offshore man-hours – are a few examples of opportunities. In addition, the vessel’s advanced technical capabilities enable it to offer a completely new service: offshore dry-docking.

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How Subsea 7 will serve Total in Angola with the unique subsea capabilities of the Seven Borealis.

An advanced vessel for West African

pipelay S

AFETY, EFFICIENCY AND effectiveness underpin Subsea 7's management and operation of its fleet. Value and integrity are key watchwords in its commercial arrangements. The company, which specialises in seabed-to-surface engineering, construction and services to the offshore energy industry, counts amongst its assets the Seven Borealis – a pipelay/heavylift vessel scheduled to serve, first, Total, at the Angola CLOV project. A recent tour of the Borealis reaffirmed Subsea 7's emphasis on safety, efficiency and effectiveness. The vessel is highly capable, and its crew are trained and supported in maintaining a strict regime of secure, systematic operation. The vessel's capabilities and equipment are extensive, too. Observe that it has its own cargo barge, to supply the vessel. See that its towers can be mobilised at each location. Understand that the main line of the S-lay system can be adjusted to suit any configuration, any process - to accommodate any client requirements. Most recently, the Seven Borealis has been sited in Schiedam, in the Netherlands, at Huisman's facility, where outfitting has been completed before mobilisation to West Africa. A global enterprise offering extensive experience in the design and manufacture of heavy construction equipment for on and offshore companies, Huisman has prepared the Seven Borealis to handle a pipe every three minutes.

More equipment for better pipelay There is more to be learnt about the vessel's capabilities. The Seven Borealis is equipped with an S-lay system to lay pipe from 11cm to 117 m. For laying pipe in extreme deep water, the J-Lay tower, positioned starboard, can be used and can lay pipe from 10cm to 61cm in water depths of up to 3,000 m. There are three two-hundred tensioners on the . There is a large red structure within - a sheath, which folds down to support manoeuvrability of the winches. There is a 600-ton abandonment recovery winch, and a 200-ton winch, both for S-lay. There is a 200-ton winch for J-lay operations. There are, also, selected small winches for specialist operations. There is a 200 metre S-lay tensioner - which consists of an upper track, a lower track and supporting equipment. It is rail-mounted, and ensures accurate load measurement. The Seven Borealis features, also, a window large enough to accommodate in-line structures - T pieces, for example - after welding. Focusing further on the vessel's heavy equipment, Mr Gilbert showed the rotary crane, which operates 600mm wire. The crane was tested at 500 tons, said Mr Gilbert, "and didn't even flinch”. Just as impressive, note here that the J-lay can turn to any angle, so that it can operate independently of the ship's own direction. Note, also, that the three-section stinger can be configured to suit specific operations. It can, in fact, create a pipe radius from 70 to 300 m. “The stinger on the Borealis is up there with one of the biggest around." said Simon Gilbert, an offshore manager at Subsea 7. Mr Gilbert manages operational matters, from crane management to pipe handling and deployment. Speaking, recently, on the deck of the Borealis, Mr Gilbert also highlighted the vessel's "world-class ROVs" - remotely operated vehicles, both of which are controlled from one controller. Additionally, the Seven Borealis has its own gas systems producing oxygen and acetylene. The commercial partnership ensuring safe and secure operation here is the technology firm iGas, which was chosen by Subsea 7 due to its experience in delivering gas supply and distribution projects throughout Europe and beyond - utilising cost-effective and advanced technology and design.

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The Seven Borealis heli-deck is notable as the largest offshore heli-deck in production.

Last to see externally, sited high on the vessel, the helideck is notable as the largest offshore helideck in production, capable of landing the largest offshore helicopters.

Evidence of advanced administration Inside the administrative bowels of the Seven Borealis, the software underpinning the ROVs is developed by Schilling Robotics. With Schilling's support, Subsea 7 designed the ROV control station in-house to exceed the concept of "fit-for-purpose" – in Simon Gilbert's words - offering capabilities that not a lot of comparable vessels have. Development of the ROV control stations may be associated with development of a paperless system for task planning. This is a technologically advanced vessel, not just in terms of its ability to deliver flexlay capabilities, but also in terms of administrative functionality. Within the Seven Borealis, one sees the deployment of an integrated system of software, hardware and defined processes to manage information through creation, capture, storage, retrieval, distribution and retention. Looking across the navigation bridge, one can affirm that there are no paper charts - it is all electronic, and with comprehensive use of GPS systems. Looking, then, for a practical example in internal and external communications, one can observe that the Seven Borealis is fitted with Cisco IP phone equipment. A few steps away from the navigation bridge, there is evidence on the chief officer's desk on the working bridge, in the form of a Cisco IP Phone 7962G – a capable, high-end unified communications device designed to meet the needs of managers and administrative assistants. With programmable buttons and interactive soft keys applicable to all call features and functions, this hands-free speakerphone and handset offers hi-fidelity wideband audio, and features a built-in headset connection and an integrated Ethernet switch, representing a sound choice of communications hardware - user friendly and one of the easiest phones to use, offering stable IP telephony (obviously, depending on the capacity and stability of data connection). Observe that even a detail such as choice of phone indicates in keeping with Subsea 7's emphasis on effective, efficient operation. ■

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GE to supply propulsion systems for new LNG ships REINFORCING ITS ROLE as a major supplier of electric propulsion technology for liquefied natural gas (LNG) ships, GE's Power Conversion business recently received a series of new orders from South Korean companies Daewoo Shipbuilding & Marine Engineering and Hyundai Heavy Industries. The GE equipment will be installed on 23 new LNG ships and represents total propulsion power of 1,105 MW. “These orders clearly demonstrate that GE’s expertise in electric propulsion for LNG applications is recognized worldwide by the major players in the sector,” said Paul English, marine vertical leader for GE’s Power Conversion business. “Our continuous investment in innovation and competitive solutions allows us to customise and optimise our offerings to meet ship owners’ specific requests.”

The scope of GE’s contracts includes MV7000 converters, induction motors, transformers, generators, main and cargo switchboards and propulsion control systems. Manufacturing for all propulsion motors is based in GE’s rotating machines plant in Nancy, France, while the propulsion systems are engineered at the GE merchant marine center of excellence in Belfort, France. GE’s motors and converter are designed and optimized to make the propulsion systems easy to maintain. The induction machines are driven by press-pack IGBT Pulse Wide Modulation (PWM) converters to offer high levels of reliability in a compact design. GE’s global electric propulsion systems provide customers with high efficiency, availability and layout flexibility.

First Smit Lamnalco branded tug launched ON 24 AUGUST, Smit Lamnalco launched SL Gabon, the first tug branded under its new corporate identity, following the integration of Smit’s terminal handling activities with Lamnalco in July 2011. Built by Damen Shipyards Galati in Romania, SL Gabon is also the first of two newbuilds contracted for a five year period by Total Gabon to provide support in the offshore oilfields and to assist tanker operations at the onshore terminal of Cap Lopez, at Port Gentil, Gabon. The second tug, SL Libreville, is due for delivery next month. “It is great that the first newbuild decked with our new corporate

colours visualises the integration of two international marine service providers,” said Smit Lamnalco CEO Daan Koornneef. The newbuilds are Stan Tug 4200type tugs, rugged twin-screw vessels with 68 tonnes bollard pull. Accommodating a crew of 16 and fully air-conditioned, the vessels can be used for towing, pushing, push-pull, berthing, anchor handling, hydrographical survey, line handling, firefighting, salvage, diving support and pollution control operations in all waters. The Total Gabon contract renews a longstanding partnership between the oil major and Smit Lamnalco.

The newbuildings replace two older Damen-built vessels, and join the existing tugs Smit Manji and Smit Ozouri, built in 2007. For Total Gabon, the latest renewal extends a relationship in Gabon that can be traced back through SMIT to 1998. “As well as symbolising the ongoing trust placed in us by our customers through our integration, the delivery confirms our willingness to commit to building new vessels for energy majors operating in promising markets,” said Mr Koornneef. “Given Port Gentil’s remote location, it is critical that marine support services are robust and reliable.”

Real-time downhole communication system THE PATENTED BAKER Hughes TeleCoil™ system offers real-time downhole information, maximising the efficiency of virtually any coiled-tubing (CT) operation. Real-time collar location enables the necessary depth accuracy for precision applications, such as perforating and zonal isolation. Bottomhole differential pressure and tool differential pressure information—with temperature data—offer continuous optimisation of a wide range of common applications including milling, stimulation, cleanouts, sand removal, debris removal, and gas lifting. The TeleCoil conductor, which is preinstalled inside the CT, is impervious to aggressive fluids such as acids, cement, and sand slurries. The smalldiameter conductor has a negligible impact on the pumping pressure drop along the coil and the overall reel weight. The TeleCoil conductor’s protective jacket is sized for the necessary strength and stiffness to withstand dynamic tension and compression forces encountered during spooling and pumping operations.

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The system—which uses standard end fittings and attaches to the BHA with mechanical and electrical quick connectors—requires only minutes to hook up in thee conductor connects to a data acquisition system that processes and charts the downhole information.

New multiphase subsea pump system

FMC TECHNOLOGIES AND Sulzer Pumps have jointly developed a powerful new multiphase pump system optimised for harsh subsea environments. The new pump system leverages Sulzer Pumps’ pump hydraulics with FMC Technologies’ high-speed permanent magnet motor technology and subsea system design and integration experience. The helico-axial type pump is powered by a 3.2-MW permanent magnet motor and is capable of withstanding pressures up to 5,000 psi. By using permanent magnet motor technology, less maintenance is required and greater speed, efficiency and power can be achieved providing end-users with more operational flexibility for subsea processing, said the companies. “The collaboration between FMC and Sulzer Pumps Ltd. has resulted in what we believe to be the most powerful, efficient, and flexible subsea pump system available on the market,” said Rob Perry, director of subsea processing at FMC Technologies. “They industry wants more energy on the mudline to support their efforts to boost production and improve economics, and I am happy to say we have delivered a solution,” Perry continued. Full qualification testing of the subsea pump unit was completed earlier this summer at Sulzer Pumps' purpose built test facility in Leeds, UK.

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THE ROBUST GO Range now provides a more compact and reliable solution for automating heavy duty valve applications found in the gathering, transmission, compression and storage of gas. Re-designed to provide longer and more efficient service in the harshest of environments with the minimum of maintenance, the new generation of Rotork GO actuators has undergone an important upgrade, including streamlined manufacturing and product improvements. As a result GO actuators are now lighter, more compact and incorporate advanced changes to functional specifications. The improved modular design enables the smallest number of components to meet a wide variety of valve torque and control requirements. The GO range uses the pipeline gas as the motive

power source. The gas is delivered to oil tanks that convert the gas into hydraulic pressure and this pressurised hydraulic oil is used to drive industry-

preferred Rotork scotch-yoke quarter-turn or linear valve actuators. A complete range of sizes is now available to suit virtually any valve size or class. Using pressurised oil as the driving force provides powerful and smooth actuator control and isolates the cylinder from the pipeline gas. This prevents contaminants from entering the hydraulic cylinder, eliminating corrosion and seal deterioration and extending actuator life. At the centre of the gas-over-oil system, the multi-function manifold block integrates gas control functions to facilitate a wide range of valve control options. Standard gas control systems are complemented with optional equipment designed by Rotork Fluid Systems for functions including Line Break, Low Pressure Close, High Differential Inhibit and Emergency Shutdown (ESD). In all cases operation is simple and intuitive.

Baker Hughes promotes technology used in Gamba reservoir well completion FOLLOWING PREVIOUS SUCCESSES in Gabon, Baker Hughes has carried out its next well completion in the Gamba sandstone reservoir using inflow control and gravel pack technology, the company said in a recent press release. The subsea horizontal well is located in the Dussafu Block Offshore Gabon and is the company’s fifth project in the region. The well penetrates the Gamba sandstone reservoir, which averages at a thickness of 45ft and overlies a significant angular unconformity, underneath which is located an oil column of approximately 170ft. The sandstone has a porosity level of around 30 per cent, with a permeability range of one to three Darcies. This contrasts with the Dentale sands which are much more variable, with levels between 18 to 30 per cent. The challenges posed by this job, as well as others in the same field, required the ability to gravel pack inflow control devices for fines control due to the complex geology, according to Baker Hughes. The completion consisted of an openhole gravel pack system, the Model CS-300™, and use of an Excluder2000™ screen with Equalizer Helix™ inflow control technology, with the length of the screens in the open

hole reported to have reached 626 m According to the company, this is the longest gravel-packed uniform inflow control completion using Excluder2000 screen with Equalizer Helix inflow control technology to date. The equipment and services for the upper completion section of the subsea well were also supplied by Baker Hughes. The Model CS-300™ system was used to ensure that hole stability was maintained during screen deployment, packer setting, and gravel packing by maintaining hydrostatic pressure on the filter cake at all times. The gravel pack held the sand in situ and maintained borehole stability by moving the sand filter to the borehole wall, ensuring completion longevity, the company claim. Baker Hughes went to identify further advantages of their method, including the fact that the Excluder2000™ screen with Equalizer Helix™ technology acts as the basis of a uniformed flow system. The benefits of such a system include the prevention of water coning in the sandstone formations and the prevention of screen plugging and erosion. Furthermore, the system enables inflow to be managed passively and eliminates axial flow by filling annulus with gravel, the company comments.

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New generation of gas-over-oil pipeline valve actuators

Technology

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Leon Bredenhann and Benjamin Yanda* look at the kinds of waste that oil and gas operations generate, the forces pushing towards more sustainable solutions to this waste problem, ways to reduce the costs of waste management, opportunities to generate revenue from waste and how these steps can help reduce long-term liabilities and risks.

From ‘waste problem’ to

‘valued resource’ T

HE OIL AND gas sector in Africa has traditionally focused much of its attention on operational concerns such as geology and geophysics, production methodology, social license to operate and transportation of hydrocarbons. Waste management, as an operational issue, has often lost in the competition of priorities. Waste materials include non-sector specific wastes such as those found on any construction or commercial site such as spent lubricating oil, vehicle parts such as tyres and filters, medical waste from clinics, kitchen waste, packing materials for equipment and consumables, and office waste. Drill cuttings, muds, produced water, hydrocarbon-contaminated soils and debris, cement, and used catalysts and testing materials comprise the bulk of sector specific wastes. Refineries, LNG plants, compressor stations, pipelines and other dedicated facilities have their own unique waste streams. A combination of factors, including higher operating standards, better environmental commitments, and increased public and regulatory scrutiny are pushing the management of waste materials up the agendas of oil and gas operators.

Rising community concern While many communities value the employment and economic activity that the oil and gas sector brings, they do not want to be stuck with waste products -- and likely have limited capacity to deal with waste. Communities living in close proximity to natural resource development, and who feel they have not been treated equitably, have participated in disrupting activities such as harassment and intimidation of employees, picketing, interruption of operations and even sabotage. They can also find powerful champions in local and international non-governmental organisations (NGOs), which can quickly mount global campaigns featuring interviews, images, and even video footage purported to be evidence of a company’s poor stewardship. Unsafe disposal and scavenging by local communities increase the potential for environmental releases. This is a particular problem for containers used to hold spent lubricants, catalysts, and other hydrocarbons, or packaging, blocking, liners, and other wood contaminated by its initial use. These may be scavenged for local use by community members and even workers. For example, when geo-synthetic liners are used as roofing and walls, and containers and filters are

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Oil and gas companies must make sure that their waste management practices do not damage the natural environment, which provides livelihood for many, such as this fishing crew on Lake Kivu on the Rwanda-Congo border.

A combination of factors is pushing the management of waste materials up the agendas of oil and gas operators. used as vessels for cooking and carrying water, the population may be put in direct contact with potentially harmful substances. Improper disposal of materials and scavenging of liners can also pollute surface and groundwater, a serious problem for communities that depend on surface streams and hand-dug wells for their water supplies, and where people may already spend hours each day carrying water. Many countries rely on tourism for foreign exchange income, with much of their population dependent in part or entirely on tourism for their livelihoods. There is the perception and concern that the resource sector’s leftovers will harm the landscape, reducing its appeal to tour companies and tourists. There are few national regulations on waste and produced water management for the resource sector, and specifically the oil and gas industry. This, however, increasingly means that internal operating standards and/or international best practices, including those developed by the IMF, the World Bank Group, and the UN are applied.

Frequently, the ‘International Best Management Practices’ and internal operating standards have been established in the developed world, where competent third-party waste managers and regulatory authorities are in place.

Missing out on opportunities Many resource companies miss out on the potential benefits available from what they may consider “waste” products, turning them from an operational expense into a positive socio-economic benefit to surrounding communities or a source of modest income, possibly both. While a heavy vehicle or piece of construction equipment may be past its service life from the company’s point of view, some effort will find a nearby buyer who will be glad to buy it -- possibly helping create employment as a result. Obsolete and surplus computer equipment can also find an eager new owner in the community. The same goes for many ‘waste’ products -- right down to the packing crates used to ship equipment. While this may not spell ‘opportunity’ in more advanced economies, in less-developed countries local people may be glad of jobs that involve disassembling packing crates, with the resulting lumber finding a new use as construction material, providing it is free of contamination. The result is that what was considered ‘waste’ can help the company generate revenue, reduce waste-handling costs, and build better relations with local communities.

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“pyramid” in which the largest percentage of waste materials is “disposed of” in a landfill, with no further use planned. Increasingly, the trend is towards reducing the amount of waste produced, re-using materials, and recycling -with disposal being considered a last, and shrinking, resort.

Locally-appropriate solutions are key

Material surplus to the oil and gas industry, such as used equipment and even packing material, can find a secondary use in local communities, helping to improve the lives of people such as these farmers in the eastern DR Congo.

Waste management’s role as a driver of operations and costs is expanding. A need to re-think developed world solutions Increasingly oil and gas operators, with strong track records outside the region, are taking significant exploration and production positions across much of the African continent. These companies, headquartered in North America, Australia, Europe and even Asia, tend toward employing solutions that work in a ‘developed world’ waste management context. Prevalent assumptions include: capital spending compensates for the high cost of labour; parts and supplies are readily available; transport over long distances is dependable with fixed times and costs; and that there is an established market and industry to handle waste materials. The African reality will require that solutions be adaptable, creative, and even tailored specifically to the particular geography and waste streams in question. In much of Africa it may be difficult to find employees able to operate sophisticated equipment, while less-skilled labour may be plentiful. Long distances, unreliable roads and in some cases, risk from civil unrest and banditry can mean that road transport is problematic. Reliable third-party waste transporters and managers may not exist in the entire region or country.

Operators will have to put considerable effort and preplanning into solutions for surplus and waste materials. But given the growing concerns about business-as-usual waste disposal, companies that make extra effort to build their waste-management skills within the specific context can be rewarded with lower costs, fewer risks, positive community relations, beneficial socio-economic impacts and a more secure and predictable environment. Waste management, from the operator’s perspective is a lowthreshold entry point where local and national companies can provide the necessary goods and services.

Begin with the end in mind Waste management has had varying degrees of importance to the oil and gas industry; however, its role as a driver of operations and costs is expanding. Part of the solution must be early ‘closure planning’ -- determine the ideal situation at the project’s end, and make it a priority part of the planning process. Active planning will include many site and project specific practices, which are not the focus of this article. A key is to make wise waste management a part of the operating culture. This will reduce long-term costs, as well as decrease environmental and social impacts, risks and liabilities. The current trend in waste management is to redesign the classic waste management

In planning for waste management and responding to issues that arise, operators must be careful to ensure that the solutions they choose are appropriate to local conditions. For example, high rainfall in some areas may result in the selection of a high-density polyethylene (HDPE) cover for a potential landfill, to eliminate infiltration into the landfill. Local communities may find that the HDPE material is a highly desirable material for roofing their own homes, resulting in the scavenging referred to earlier. Another technique, easily implementable for low cost that will eliminate potentially hazardous scavenging is to shred all materials prior to transport. A strong planning team, including advisors experienced in waste management issues, particularly in providing solutions in an African context, is a big part of success. Community understanding and consultation are a critically important part of developing good relations with local communities and thereby increasing the chance of successful projects. This must include the waste management process where conflicts and misunderstandings have developed many times in the past and across many regions, including outside of Africa. Good relations with local communities must include the leaders, the average stakeholder, and those most impacted by the project components. These relationships should be developed in the stakeholders’ language and tailored to meet them in a proactive but equitable engagement. This will assist to minimize conflict and create solutions -possibly even establishing ways to reuse the company’s waste materials. ■

* Leon Bredenhann, Associate, is Divisional Leader: Integrated Waste Solutions with Golder Associates Africa (Pty) Ltd. based in Pretoria. Benjamin Yanda is Oil and Gas Sector Leader for Africa with Golder Associates in Durban

Caterpillar’s new transmission for well fracturing CATERPILLAR HAS INTRODUCED its new Cat CX48-P2300 transmission, designed specifically for hydraulic fracturing associated with well stimulation and completion. Weighing in at 1,601 kg, the CX48-P2300 is the lightest weight transmission available for frac applications. With an input power of 1,716 bkW and peak input torque of 9,024 N•m, the CX48-P2300 also features improved durability to match engine life, and an industry-high horsepower-to-weight ratio. Its cutting-edge controls are tailored for the frac market, with a focus on safety and flexibility. The starter interlock feature ensures the engine cannot be started while the transmission is in gear, and the quick-to-neutral switch allows the operator to put the transmission in neutral immediately. “We designed this petroleum transmission for the specific needs and

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demands of heavy well fracturing applications,” said Carl Thiele, Caterpillar Global Petroleum technical sales manager. “This transmission offers increased reliability and durability, and yet is simple to install and maintain, resulting in lower owning and operating costs, and reduced downtime – all things that are of utmost importance to our customers.” Features enabling the simplified installation and maintenance include an integral PTO; integral filters with bypass indicator; reduced external hoses; rigid-mounted ECU with wire harness and remote mount capability; low oil level indicator and oil pressure monitoring. Cat engines, generator sets and transmissions are backed by the worldwide Cat dealer network with trained technicians to ensure service support is never out of reach.

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GE unveils new wellhead solution GE INTELLIGENT PLATFORMS has unveiled a new production wellhead equipped to deal with harsh environmental challenges. The company said in a statement that the wellhead solution can "survive temperature extremes from the desert heat of the Arabian Peninsula to the Arctic cold of Siberian oilfields". The wellhead comes with integrated logic control and safety functions that enable easy detection of fire and gas detection, as well as an emergency shutdown mechanism. "In addition, it enables rapid implementation from discovery to startup so operators can achieve faster recovery of oil and gas," the statement said. "The unique combination of integrated control and safety, environmental ruggedness and low power consumption makes this wellhead control solution ideal for E&P operators to increase production uptime and asset performance while lowering total cost of ownership." GE also said that, compared to traditional deployments and systems without diagnostics, its new wellhead solution provides 50 per cent faster deployment, a 35 per cent reduction in engineering costs for expansions and maximised production with 65 per cent reduction in field service cycle times.

Baker Hughes expands line of AMT cutters BAKER HUGHES RECENTLY introduced Metal Muncherâ&#x201E;˘ AMT (advanced milling technology) cutters to achieve greater efficiency and longer runs with cutting and milling systems used for casing exits and wellbore intervention. Clean and efficient milling operations help operators reduce risks and prevent nonproductive time. The new cutting structures, featuring insert shapes and metallurgies customised for specific applications, provide more efficient cutting and enhanced durability and impact resistance, resulting in longer runs and fewer trips. Engineered using pressed sintered tungsten carbide, the AMT cutters are available in a variety of shapes and metallurgies. Depending on the application, a milling tool may include several types of AMT cutters to optimise various aspects of the milling operations. The cutters are designed to mill even the toughest steels, including high chrome and nickel-content materials. The durable technology increases milling penetration rates, extends effective time on bottom in high volume milling applications, and enables greater flexibility during the milling process.

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ICT

Intersect next-generation reservoir simulator SCHLUMBERGER, CHEVRON AND Total have announced that Total is joining the collaboration to further develop the Intersect next-generation reservoir simulator. Total will contribute engineering resources and expertise to expand the Intersect simulator effort. The Intersect simulator is an industry first, combining Chevron’s reservoir simulation capabilities and reservoir management experience with the leading software

development capability and commercial experience of Schlumberger. Using advanced mathematical techniques, the Intersect simulator goes beyond the capabilities of current-generation software to simulate large and complex reservoirs using high-resolution models. This allows operators to test a large number of scenarios to increase the effectiveness of development plans and design innovative production systems to maximise

field recoverable reserves. "We look forward to a productive partnership between the three parties and welcome the contribution of Total to continue to broaden Intersect’s capabilities," said Ashok Belani, executive vice president, Technology, Schlumberger. "The jointly developed product will leverage the practical and global expertise of Chevron and Total in managing diverse and complex oil and gas reservoirs.”

Redline’s new wireless oilfield network REDLINE COMMUNICATIONS GROUP, a leading provider of broadband wireless solutions for machine-to-machine (M2M) communications, has announced a significant contract with a leading American oil and gas company for a highcapacity wireless network for communications between wells, other assets, and drilling rigs in the oilfield, and their centralised control offices. This oil company customer, already using Redline’s system in other parts of the world, is expanding its operations to Oman and has turned to Redline once again to meet their exacting communications requirements. Delivery of products and services associated with the contract, which is expected to represent approximately 10 per cent of Redline’s annual revenue for 2012, begins immediately with full deployment of the network expected to take up to 18 months. “This contract is a major achievement for Redline and we are proud to have

been selected as the network backbone for yet another oilfield project with this customer,” said Eric Melka, CEO of Redline. Redline’s advanced wireless broadband system, which leads the industry in reliability, distance, capacity and low-latency, allows personnel to monitor and control oil field production – including the ability to capture data in real-time from thousands of M2M sensors at remote sites. The Virtual Fiber™ network will be built using Redline’s RDL-3000 and ELTE-MT systems, rugged and reliable wireless broadband equipment designed by Redline for harsh environments, and engineered and built to the exacting standards required by the energy sector. “Major oil and gas producers worldwide are turning to real-time monitoring and control capabilities to expand production at new, existing and mature oilfields,” said Bojan Subasic, Redline’s associate vice president development and production.

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Montgomery Libya (Oil & Gas Libya 2013) ..............43 NHV Aviation ..............................31 Nynas South Africa ..................36 Oil Country Tubular Ltd (OCTL)....................65 PEM Offshore Inc. ......................23 PennWell Corporation ............83 Petroleum Agency South Africa ................................37 Portwest Clothing Ltd. ............55 Prakash Steelage Limited ......73 Rana Diving S.p.A. ....................39 Red Helix International Ltd. ..44 RWE Dea AG ................................51 Saudi Leather Industries Company Ltd...............................85 SGS Inspection Services Nigeria Ltd..................49 Smit Lamnalco Netherlands b.v..........................20 South Atlantic Petroleum ........2 Spina Group S.r.l.........................13 Standard Bank (Stanbic)............9 Tilone Subsea Limited ............19 Tolmann Allied Services Company Ltd ..............................33 Toprope ........................................35 United Metallurgical Company / JSC OMK ................87 Yahsat ............................................15

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