Plenty more from Africa
Africa's LNG export capacity – already more than a quarter of the world total – could double over the coming five years, with more to come after that if plans under discussion firm up. The main brakes on development are rising construction costs and, in Nigeria, security concerns, Martin Quinlan writes
ALGERIA was the world's first liquefied natural gas (LNG) exporter, but it was many years before Africa's other big gas countries were in a position to join the trade. Now, however, there is no stopping them. Africa's existing LNG export capacity of 57.5m tonnes a year (t/y) will increase by 28% (16.1m t/y) by 2012 from projects already going ahead, and by an additional 44.9m t/y by 2014 from projects still subject to final investment decisions (see Table 1, p20).
The five African LNG exporters – Algeria, Nigeria, Egypt, Equatorial Guinea and Libya – all have projects for new capacity either under construction or in planning. In 2012, they will be joined by Angola, which also has additional capacity planned. Mauritania and other countries are trying to prove up sufficient gas reserves to join the club. The commercialisation of floating liquefaction technology – the world's first unit was ordered in September (see p22) – should allow many more countries, led by Namibia and Cameroon, to join the exporters.
Algeria's bold decision
Despite its heritage in LNG, Algeria has been overshadowed by Nigeria's rapid growth as a producer since the first trains at the Bonny island complex started up at the end of 1999. But this year has seen Algeria re-establish its credentials: in July, state-owned Sonatrach took the bold decision to build a new liquefaction facility on its own, without the involvement of an international specialist partner (PE 9/08 p2). The firm awarded the construction contract for the new unit, at Arzew, to a venture between Snamprogetti, Saipem and Chiyoda.
Sonatrach started down the go-it-alone road in July 2007 when it placed a contract for a new train at Skikda, to replace the three destroyed in an explosion in January 2004. The new train, being built by KBR, will raise the country's capacity to 24.3m t/y in 2011, with the total rising to 29.0m t/y the following year when the new Arzew facility is due for completion.
If Nigeria LNG's planned Train 7 goes ahead fairly soon, that should also be completed by 2012 and the Bonny island site will have a capacity of 29.6m t/y. Nigeria's growth in LNG has been driven by the government's penalty-backed programme of eliminating the flaring of associated gas, and aided by innovative offshore financial arrangements – but new projects are threatened by the terrorism problem in the Niger delta, as well as the escalating costs of operating in the country.
Plans for two new complexes, Brass LNG, at Brass, on the southern part of the delta, and OK LNG at Olokola, on the delta's western coast, were launched in 2003 and 2005 respectively, with targets for both to be completed by now – but both are still short of their go-ahead decisions. The Eni-led Brass project is said to be ready to go – the site has been obtained, financing arrangements agreed, sales contracts initialled and in June 2007 Bechtel was awarded the project-management contract. Brass LNG did not answer questions about the status of the project, but it seems the terrorism problem in the delta and uncertainties over the government's fiscal treatment of gas, are behind the delay.
Gas limits in Egypt
Egypt burst into the LNG business in 2005, when all three of its existing trains – one at the Segas facility at Damietta and two at the BG-led ELNG complex at Idku – started up. But there are signs that the rapid build-up in capacity has run ahead of gas availability, with operating rates limited by the volumes being made available by state-owned Egas. The country's deliveries in 2007 amounted to 13.5bn cubic metres (cm) according to Cedigaz, indicating an overall utilisation rate of 80%. Destinations were Spain (30% of the total), France (9%), other European countries, the US (24%), Mexico, Japan (12%), South Korea (11%), Taiwan and India.
Plans for a second train at Damietta were launched by Eni and its partner in Segas, Spain's Unión Fenosa, in 2005, but they were dependant on sufficient gas reserves being proved-up in Nile delta licences off Damietta (PE 3/08 p10). Discoveries have been made, but the breakthrough came early this year when BP, operator for a 50:50 venture with Eni, made an apparently large discovery in a high-pressure, high-temperature structure in the North El-Burg licence, 50 km off Damietta.
Eni immediately said the discovery, named Satis, together with other finds made in the previous two years would allow partners in Train 2 to launch the development this year. Satis has given a new impetus to exploration because, at 6,500 metres depth, the well was the deepest yet drilled in the country and it raises expectations for other deep reservoirs in the Nile delta. Water-depth at the find is relatively shallow, at 90 metres.
Eni's outline agreement covering Train 2 already provides for BP to join the participants, as the train's gas supplier – but there are industry suggestions that BP is pressing to go further and join Eni and Unión Fenosa in the Segas company, through which it would gain a stake in the first train. Meanwhile, Germany's RWE Dea has declared an interest in joining the Train 2 participants – it is BP's 40% partner in the North Alexandria A licence, which holds the Raven and last year's Taurus Deep gas discoveries.
Not to be outdone, BG points out that its Idku site has space for four more trains and hints that gas owners could participate in the ownership of a new train, or alternatively the train could be supplied by third parties. Earlier this year, the petroleum minister, Sameh Fahmy, said that, because of surging inland use, there would be a freeze on gas-export projects until 2010. But he qualified the statement by saying it applied only to the state's share of gas – the Damietta expansion, and presumably also an Idku expansion, would not be affected, he said.
BG confirms that a new train at Idku is a longer-term plan. Meanwhile, it is making more gas available to the inland market, and it is also tolling its own gas through its competitors' facility at Damietta. The firm lifts 0.7m t/y of LNG from Damietta under a five-year contract, but the volume will reduce to 0.5m t/y next year.
Africa's newest and southernmost LNG exporter, Equatorial Guinea, claims an edge in costs. The Marathon-led EGLNG complex at Punta Europa, on Bioko island, was built at an engineering, procurement and construction cost of $270 per t/y of capacity, EGLNG claims, and within the $1.5bn overall budget.
A short project cycle-time helps meet financial targets. At EGLNG, the first cargo, loaded in May last year, was exported only three years after the final investment decision and the award of the construction contract, to Bechtel. EGLNG attributes the short construction period to "government and shareholder alignment", the advance order of long-lead equipment and the experience of the contractor with ConocoPhillips' Optimised Cascade liquefaction process.
EGLNG has bold ideas for its planned second train: it is envisaged as the world's first LNG facility to be supplied with gas across national boundaries. Under outline agreements signed last year with Nigerian National Petroleum Corporation and Cameroon's Société Nationale des Hydrocarbures, gas is to be piped a fairly short distance – about 100 km – from fields off eastern Nigeria and in Cameroon's Rio del Rey and Douala offshore basins.
There is also more gas to be tapped in Equatorial Guinea's waters, where Marathon's Alba field provides the 6.2bn cm/y of feed gas for Train 1. According to EGLNG, there are potential reserves of 0.85 trillion cm within 100 km of Punta Europa, which could be processed at "multiple" LNG trains producing up to 20m t/y. EGLNG has been targeting a final investment decision on Train 2 this year, but made no comment on the project's status last month.
Libya making up for lost time
Libya, Africa's smallest LNG producer, is now set on making up for its wasted years as a gas exporter. The country once had an eminent position in LNG: its Exxon-built facility at Marsa el-Brega was the largest in the world, by a considerable margin, when it started-up in 1971. But politics intervened, with aggressive price-rises, disputes and the eventual take-over of the facility by the state's National Oil Corporation.
Marsa el-Brega continues in operation, with capacity limited to about 0.6m t/y, but is to be renovated by Shell as part of the major's agreement to return to the country. Capacity is to be raised to 3.2m t/y, if Shell proves up sufficient feed-gas in its Sirte basin licences, nearby. Shell also has plans for a new LNG-export facility, as do Eni and BP, but all are subject to discoveries being made in the drilling programmes that are only just starting (PE 10/08 p4).
Angola, which is set to become the continent's sixth LNG exporter, in early 2012, could see rapid expansion because Eni – a participant in the Chevron-led ALNG venture, building the 5m t/y facility at Soyo – has already launched the process that could lead to a second train. Supplying gas to the first train will involve construction of an extensive offshore gathering system, the cost of which could be shared advantageously between two trains.
According to ALNG, three gathering pipelines will be built. One will extend north to the Cabindan offshore, collecting gas from the Chevron-operated Blocks 0 and 14; one will extend west, into ExxonMobil's Block 15; and one will run south and divide, to collect gas from Total's Block 17 and BP's Block 18.
ALNG says the system will collect mainly associated gas in the early years, although some non-associated gasfields in Blocks 1 and 2 will be connected to give security of supply. Reserves of 297bn cm have been identified, ALNG says. The first train will call for 6.8bn cm/y of feed gas, but there are plans for the gathering system also to land up to 1.3bn cm/y for industrial use in Angola.
World's first floating LNG production
OFFSHORE production of liquefied natural gas (LNG) is due to become a reality in 2011, following the order of the world's first floating liquefaction unit in September, writes Martin Quinlan.
Norway-registered but UK-based Flex LNG signed a contract for the ship-shaped LNG floating production, storage and offloading (LNG-FPSO) vessel, with a production capacity of 1.7m tonnes a year (t/y), with South Korea's Samsung Heavy Industries (SHI).
The go-ahead for offshore liquefaction – coinciding with the installation in September of the world's first offshore regasification terminal, off Italy – marks the coming-of-age for floating LNG technology, after two decades of development. LNG-FPSO units will be able to tap stranded fields, too small or too far from the market to be developed up to now, sharply increasing the supply of LNG.
Flex LNG, set up in 2006 to develop its LNG Producer concept in association with SHI, had earlier ordered hulls for four LNG-FPSOs from the firm. The September signing covers the construction and installation of an SHI-developed topsides liquefaction facility onto the first hull. SHI says the engineering, procurement, construction, integration and commissioning contract is worth just over $1bn, made up of $0.551bn for the topsides and $459m for the hull.
The first LNG Producer vessel will be installed in Nigeria to process gas from the Bilabri field, lying about 50 km off the western part of the Niger delta in the mostly shallow-water OML 122 licence. The licence is held by Peak Petroleum, a privately owned Nigerian firm controlled by the Oluokun family, but the company has formed a venture – Progress LNG, made up of Peak, Flex LNG and Mitsubishi – to carry out the development. Mitsubishi will lift the LNG.
The Bilabri facility is due to sail away from SHI's yard in third-quarter 2011. The production rate will be 1.5m tonnes a year (t/y), plus condensate, and a project duration of 15 years is expected. Peak was awarded the OML 122 licence, in which Bilabri had been discovered by an earlier operator, in 1993, under the government's indigenisation scheme.
Flex LNG says its second LNG Producer is destined for Papua New Guinea, under an outline agreement with UK firm Rift Oil, to produce a stranded onshore gasfield. Gas will be piped offshore to the LNG-FPSO, which is expected to produce 1.5m t/y of LNG from the first half of 2012. Flex LNG claims its third and fourth units will also be starting up in 2012 – but says its competitors, if they secure a construction slot before the end of this year, will not be producing LNG until the second half of 2013.
Flex LNG says the order for the first unit confirms its earlier forecast that capital expenditure will fall in the range of $550-$700 per t/y of liquefaction capacity – the cost of the Bilabri unit works out at $594 per t/y. LNG Producer costs are competitive with historical costs for onshore facilities and much lower than recent onshore costs, which the firm estimates to have risen to $1,300-$1,500 per t/y.
The economic reserves threshold for developing a field with an LNG Producer is about 14bn cubic metres (cm), the firm says, compared with upwards of 170bn cm for an onshore facility. It sees Africa and southeast Asia as the main markets for its facilities, citing analysis by Wood Mackenzie, an energy consultancy, that claims the two regions hold 4.25 trillion cm of stranded gas in reserves of 8.5bn-42.5bn cm.
Also supporting the LNG Producer concept are the growth of LNG shipping capacity – now "a true commodity service", Flex LNG says, with a large number of operators – and the growth in world regasification capacity, which the firm forecasts will be about three times greater than liquefaction capacity by 2010. The lead-time to develop a field with an LNG Producer is less than half of that of an onshore facility.
Flex LNG said in September that it had raised equity totalling $0.570bn in three transactions over the past 18 months, and is debt-free. Its largest shareholder is Japan's K-Line, with 15%. The firm has 38 employees at its offices in London and Oslo.
LNG Producer vessels have a storage capacity of 170,000 cm of LNG, in four SSP Type B tanks, and an optional 50,000 cm of storage for condensate. All have a liquefaction capacity of 1.7m t/y, using the nitrogen-expansion cycle process. The LNG is transferred to an export vessel moored side-by-side, although tandem mooring is said to be a future possibility.
SHI said it is developing an LNG-FPSO of over twice the size of the first unit and expects to build three or four a year.