East Africa’s big offshore gas prizes carry big challenges
Vast gas discoveries off Mozambique and Tanzania are set to turn an energy-deficient region into one of the world’s largest sources of liquefied natural gas – but the challenges of commercialisation are as large as the prizes
In less than three years, drilling off the East African coast by operators Anadarko, Eni, BG and Statoil has given the world a new gas province. Exploiting the vast, high-quality reservoirs, not too far offshore and at water-depths which are not extreme by today’s standards, should bring great benefits to the region, while feeding the world’s demand for liquefied natural gas (LNG).
But developing the fields and bringing the gas to market will involve great challenges. For the host countries, the capital spending will be huge in relation to the size of regional economies, bringing the risks of overheating and exchange-rate upheavals, while inflows of skilled workers from overseas could lead to alienation locally. The management capacities of governments and national oil companies will be severely strained by the growth of their hydrocarbons sectors. There is also the risk – as seen elsewhere in Africa – that oil and gas finds will stir-up old rivalries, leading governments to spend much of their new wealth on their militaries.
For the companies, financing the huge investments – Anadarko estimates $15 billion for the first two LNG trains in Mozambique – will be made more difficult by the countries’ lack of a track-record with such large projects. Many corporate and legal and tax aspects have yet to be settled. Decisions have to be taken on how the necessary infrastructure – including deep-water ports, roads, service bases and accommodation – is to be provided.
On top of this, there are market uncertainties. Worldwide demand for LNG has expanded strongly with barely a blip, growing by a compound average of over 8% per year since 2000, according to the BP Statistical Review of World Energy. But the growing market has attracted a surge of new production capacity: worldwide, LNG projects adding up to over 110bn cubic metres a year (cm/y) are under construction for completion over the years to 2017– an addition equivalent to nearly a third of present capacity. Most were launched before the recent expansion in gas supply from shale sources, which has reversed forecasts of a growing US import market for LNG into likely US exports.
But much depends on price, and East Africa’s prospective LNG exporters believe that their large new facilities will have a competitive advantage in Japan and South Korea, the world’s largest LNG markets. There are forecasts that expansion plans in Australia, aimed at those markets, will be scaled back because costs will be higher than in East Africa.
With the large volumes of gas likely to be available, utilisation is not limited to LNG. However, LNG is seen as giving the best returns. According to a study carried out in August for the Mozambique government by ICF International, an LNG scheme would give a netback value for the input gas of $6.1-11.5 per million British thermal units (Btu), while a gas-to-liquids project would give a netback value of $3.1-9.9/m Btu.
Using gas for electricity generation would give a netback value of $9.0/m Btu, while using it as feedstock for a methanol plant would give $3.0-7.9/m Btu and use as feedstock for urea manufacture (for fertilisers) would give $0.9-11.7m Btu – and the latter three would accommodate much smaller volumes of gas than LNG or gas-to-liquids. The study recommended that a pipeline should be constructed to supply gas to small enterprises in the country.
Figure 1: Worldwide LNG consumption
Having made the first and the largest discoveries in the new province, Mozambique has first-mover advantage. According to plans set out by Anadarko, operator of Area 1, a final investment decision on an LNG facility with an initial two trains will be taken at the end of next year, with the target of exports starting in 2018.
Anadarko’s Prosperidade field – a huge continuous area made up of the Windjammer, Barquentine, Lagosta and Camarão discoveries – is now appraised and wells have been tested. Outline development plans call for subsea production facilities, about 55 km offshore, landing gas to the 10m tonnes a year (t/y) LNG complex, to be constructed near Pemba on the Cabo Delgado coast.
But there is a snag: Prosperidade almost certainly extends into the adjoining Area 4, where Eni operates and has discovered the likely extension, which it calls Mamba. Prosperidade-Mamba will have to be unitised before development work can move ahead – talks between the two operators have started, but the process could be long and further delineation drilling might be necessary before an agreement on the distribution of reserves is reached. Another problem is that the unitised licence group will be cumbersome, with nine participants spanning US, Italian, Portuguese, Indian, Japanese and Thai interests and Mozambique’s state company ENH.
Accordingly, Anadarko has changed tack. In May and June the company found gas with two wells in a separate structure, Golfinho-Atum, just northwest of Prosperidade, and immediately started a four-well appraisal programme with a view to making the field the source for the initial LNG development. Golfinho-Atum has a number of advantages over Prosperidade: it lies entirely within Area 1 and so will not need to be unitised, it is nearer the coast at less than 20 km offshore, and the water-depth is 1,000 metres compared with about 1,500 metres at Prosperidade.
Eni is thinking the same way. In August it announced its fifth gas discovery in Area 4 with a well, Mamba Northeast-2, drilled in the eastern part of the block – and finding gas which is contained “exclusively” in the block, the firm said. According to the company’s estimate, it has enough gas located exclusively in the block to support its own LNG scheme.
Only 16 exploration and appraisal wells have been drilled in the two blocks, but estimates for the volumes of gas found are breathtaking. Anadarko says it has up to 850bn cm of recoverable gas in Prosperidade and up to the same volume in Golfinho-Atum, giving a total for Area 1 in the range 850bn-1,700bn cm recoverable. Upside extends to 2,830bn cm from known reservoirs, and there are other structures still to be drilled. Eni’s latest estimate for Area 4 is 1,980bn cm of gas-in-place, of which “at least” 566bn cm lies entirely within the block.
The figures point to the two blocks together holding over 3,000bn cm of recoverable gas – equivalent to two-thirds of Algeria’s entire reserves. With a 5m t/y LNG train consuming 250bn-300bn cm of gas over a project-lifetime, the reserves discovered could support as many as 10 trains, with additional gas supplied for inland use.
Tanzania and Kenya
Just north of Mozambique’s fields, BG has substantial discoveries in Tanzanian waters. Six wells in Blocks 1, 3 and 4, drilled over the past two years, have produced six consecutive finds – Pweza, Chewa, Chaza, Jodari, Mzia and Papa, in water-depths ranging from just under 1,000 metres to 2,186 metres.
BG’s partner, UK company Ophir Energy, estimates that the three blocks hold 382bn-595bn cm of gas-in-place – “meeting the threshold for a two-train LNG development”, the company says. The anchor discovery for the development is seen as Jodari in Block 1, found in March and lying about 40 km off Mtwara port in 1,150 metres of water. Ophir’s gas-in-place estimate for Jodari is 127bn cm.
In late-September BG started a three-well appraisal campaign at Jodari, with wells at Jodari North, Jodari South and a sidetrack, to be followed by a production-test in the first quarter of next year.
Tanzania’s southern offshore has also yielded two large gas discoveries for Statoil, operator of Block 2. In February the company announced a “high-impact” discovery with its first well, Zafarani-1, which it said had located up to 142bn cm of gas-in-place, and it raised the estimate to 170bn cm after drilling a sidetrack. The second well, Lavani-1, drilled 16 km southwest of Zafarani, made a find holding 85bn cm in-place. Water-depths are 2,582 metres at Zafarani and 2,400 metres at Lavani.
Illustrating the uncertainties of new-province operations, in September the government ordered the Tanzania Petroleum Development Corporation to carry out a review of the 26 current production-sharing contracts, “to ensure the country gets a fair share of its resources”. However, the energy and minerals ministry subsequently gave an assurance that existing contracts would be respected, saying the purpose of the review was to contribute to the development of a gas policy – due to be presented to parliament in the session opening in October.
The opening of the country’s fourth offshore licensing round – originally scheduled for last year, then set for September this year – has also been postponed again, until after the gas policy is decided. The round will offer nine blocks extending north from the southern border and lying east of existing licensed areas. Water-depths are in the band 2,000 metres to 3,000 metres.
In September came the news that East Africa’s gas could extend as far north as the mid-part of the Kenyan coast. Apache made a discovery with its first well in Block L8 – Mbawa-1, drilled about 70 km off Malindi. The well passed through three gas zones totalling 52 metres net, making the first hydrocarbons discovery in Kenyan waters.