Ghana's Jubilee lights the way for exploration hot-spots
Strong oil prices in the past decade have opened new oil and gas territories around the world, all offering unique opportunities and hurdles
A MERE three and a half years since its discovery, oil is flowing from Ghana's deep-water Jubilee oilfield. And further finds along the west African coast, as far along as Sierra Leone, have opened up a whole new oil province. But although the west African transform margin – an area between two tectonic plates – has come on fast, it is only the frontrunner of a number of potential new hydrocarbon-producing regions.
Tullow Oil and Texas-based Kosmos found the 1.8bn barrel Jubilee oilfield, which came on stream in December, off Ghana's coast in 2007. Initial production will be 120,000 barrels a day (b/d), which is expected to double over three years.
With the start-up of Jubilee, Ghana becomes a significant oil producer and further offshore exploration is under way. Appraisal work is being conducted on the Owo and Tweneboa fields, to the west of Jubilee, which are likely to be developed in 2012. The fields lie in the Tullow-operated Deepwater Tano licence, in which Anadarko is also a partner.
In November, Anardarko discovered oil with its Mercury-1 well offshore Sierra Leone. The find breaks down as 34.7 metres of zones with 34-42°API crude and 6.4 metres with heavier 24°API crude. The block where the find was made is held by Anadarko, Repsol and Tullow. Mercury is Anadarko's second find the in the region after Venus, the first deep-water well drilled off Sierra Leone.
The finds add to growing evidence of a significant new oil province. The west African transform margin spans nearly 1,500 km, from Ghana in the east to Guinea in the west. Anadarko says 3-D seismic shot over its five licences spanning Sierra Leone and Liberia show 17 prospects. Including its Ivory Coast and Ghana assets, the total is 30.
Offshore Liberia, Chevron bought a 70% interest and operatorship of three blocks in September. The deep-water LB-11, LB-12 and LB-14 blocks cover around 9,600 square km, with LB-14 sitting alongside Anadarko acreage with identified prospects. Chevron began a three-year exploration programme in December.
This transform margin is the fastest-emerging hydrocarbons region in the world. Jubilee took just three and a half years to reach first oil and Keith Myers, head of Richmond Energy Partners, a consultancy, says other finds in the region could come on stream with similar speed.
However, regulatory regimes have not kept pace with development schedules and this may hold up future development. And the petroleum geology in the region is as complex as the politics. "It's looking promising, but direct detection through geophysics is not foolproof," says Myers. "There will be more dry holes drilled before the sweet spots are found."
In Mauritania, further north, beyond the transform margin, a small amount of offshore production has been taking place since 2006 at Chinguetti field, now operated by Petronas, which has resources estimated at around 123m barrels. As well as the discoveries of the larger Banda and Tiof fields in 2003 and the smaller Tevet in 2005, various exploration projects are afoot.
In fourth-quarter 2010, Dana Petroleum spudded the offshore Cormoran-1 well, around 150 km north of Chinguetti and 2 km south of the Pelican-1 discovery, made by Dana in 2003. The well, in around 1,600 metres of water, discovered gas, with stabilised gas flow rates of 22m-24m cubic feet a day at one of the gas columns. Pelican-1 and Cormoran-1 are in Block 7, and Dana, which also has licences in blocks 1 and 8, has a licensed area of 34,000 square km offshore, equivalent to more than 150 UK Continental Shelf blocks.
The area around the Falkland Islands was one of the buzz points for potential new oil territories in 2010. UK independent Rockhopper's stock rose by around 600% between 5 May and 10 May on news of its Sea Lion oil find, in the North Falkland basin. By September, its stock had risen by almost 1,300% from its May value, following a technical update on the finds and plans to start drilling exploration and appraisal wells in mid-January.
Rockhopper estimates reserves are around 242m barrels and says tests confirmed medium-gravity crude in two columns. The company's economic model suggests a standalone field of 60m barrels of recoverable oil would be commercial at an oil price of around $50 a barrel.
But there has also been some fallout in the region. At the end of December, Desire Petroleum's stock fell by 29% on the news that it had failed to find oil in its Jacinta well, also in the North basin. And in September, BHP Billiton dropped out of a joint venture with Falkland Oil & Gas after the Toroa prospect, in the South basin, came up dry.
Sea Lion remains the only discovery by the four oil companies still operating in the region – Rockhopper, Desire, Falkland Oil & Gas and Borders & Southern – and is a prime example of smaller companies taking a big risk. The region is remote and has no infrastructure in place. And ownership of the islands, which belong to the UK, remains contentious: Argentina, which calls the islands the Malvinas, also claims them, and will not allow any of the companies to enter its territorial waters.
The four London-listed companies had to raise £250m between them to transport the Ocean Guardian rig from Scotland to the South Atlantic and most oilfield services are being sourced from Aberdeen. The explorers are contracting the Ocean Guardian on a per-well basis, on rotation.
In true frontier style, exploration in the Falklands basin is characterised by uncertainty. "We'll just have to wait and see," says Juliette Kerr, an analyst at IHS Global Insight. There has been a lot of hype in the UK press about the Falklands and possible reserve prospects. "These are relatively uncharted waters," says Kerr, "and this is very high-risk exploration."
The Arctic is considered the final frontier of hydrocarbon exploration. The US Geological Survey (USGS) estimates the region has recoverable undiscovered reserves of around 90bn barrels of oil and 50 trillion cubic metres (cm) of gas – around a quarter of the world's undiscovered resources. Of those, around 80% is offshore.
But the logistics involved in producing and shipping offshore Arctic oil and gas could be hard to handle – the cost of developing infrastructure is particularly high because of harsh conditions. In the case of oil, transportation costs are also likely to be high. Unless the prospects are relatively close to the shore, gas is even more of a problem in the short term, with prices at all-time lows and a glut of supply on the world market.
Potential Arctic liquefied natural gas projects may not be economically viable for years to come. Gazprom, for example, has delayed its ambitious Shtokman project, in the Barents Sea, by three years, to 2016 – and many analysts are sceptical even of that target.
Environmental concerns are also a worry because of the Arctic's pristine, fragile ecosystem. These concerns have been compounded by the Deepwater Horizon disaster in the Gulf of Mexico (GOM). Before the oil spill, governments were ready to grant approvals for Arctic developments, including offshore Norway's Lofoten Islands in the Barents Sea and Alaska, but the GOM disaster changed this. Shell has spent almost $4bn prospecting in the Beaufort and Chukchi seas, for example, but government approval for exploration drilling was withdrawn following the GOM oil spill.
For most of the relevant governments, the fear of oil spills in the Arctic is greater than the lure of potential monetary gains. Greenland is the exception. Cairn Energy found oil and gas in one of its Baffin Bay blocks off the island's west coast in September, raising the prospect of a regional drilling boom. The discovery increased interest from bigger companies, but also provoked an environmental backlash, with Greenpeace activists attempting to halt the drilling programme.
The USGS says there could be up to 31bn barrels of oil equivalent (boe) offshore eastern Greenland and a further 17bn boe to the west.
Cairn drilled three wells in Baffin Bay in 2010. It was the first company to drill, after taking licences in 2007, along with ExxonMobil and Chevron, and has interests in eight offshore blocks adding up to around 72,000 square km. Cairn will return to Baffin Bay this summer to drill up to four new wells with two rigs.
Greenland Bureau of Minerals and Petroleum awarded three of the 14 blocks on offer in the 2010 Baffin Bay licensing round in November. Shell will operate block 5 with 41.1%. Other shareholders are: GDF Suez (26.3%), Statoil (20.1%) and Nunaoil (12.5%). Shell will also operate Block 8 with a 46.4% stake, and is joined by GDF Suez (26.3%), Statoil (14.9%) and Nunaoil (12.5%). Mærsk won frontier block 9, covering 11,802 square km, and is planning seismic acquisition.
First oil production, if a commercial find is made and reserves are proved, is achievable within eight to 10 years, according to some analysts. But Claudia Mahn, an analyst at IHS Global Insight, says it would take more like 15 years, based on Greenland's stringent clean-up provisions for license holders, the present state of exploration and environmental opposition. All in all, she says: "Stakes and risks remain high with an inhospitable environment and disappointing past drilling results."
The Leviathan gasfield, discovered in December 2010 offshore Israel, holds an estimated 450bn cm, claims Noble Energy. This, says the US independent, would make Leviathan one of the biggest deep-water gas discoveries in the past decade and transform the Israeli economy.
Leviathan, for which Noble is operator, is 47 km southwest of the Tamar gasfield – also operated by Noble – which is estimated to contain around 225bn cm. Tamar's gas, which is due on stream in 2012, added to that of other smaller fields, could fuel Israel's power sector for decades. With Leviathan included in the mix, Israel could become a significant gas exporter. The country imported over 52% of its gas demand in 2009, according to Cedigaz.
But bringing so much gas on stream will be costly; and despite the scale and potential of the find, the Israeli government is also beginning to worry potential investors with plans to change the tax regime.
Under present Israeli law, tax incentives and low royalties mean the country receives, by international standards, a relatively small slice of the profits from gas production. However, in January, a government-appointed committee recommended pushing the state's revenue share up from 30% to somewhere between 52% and 66%.
These recommendations must still be approved by parliament, but Noble, Delek Energy – a partner in both fields – and others have spoken against them. Noble chief executive Chuck Davidson said such a change would "quickly move Israel to the lowest tier of countries for energy investment". Delek said such changes would cause "irreversible damage" to Israel's energy sector.
Tamar is likely to escape the full extent of any changes to the fiscal regime. The government committee proposed an agreement under which profits from Tamar and similar fields will be subject to a government levy of 43-59%, if they come on stream before 2014. Leviathan would be subject to the full tariff, which could be as high as 66%.
There are also political obstacles to developing Israel's offshore gas finds. In December, Israel and Cyprus agreed new maritime boundaries. Under the UN Convention on the Law of the Sea, countries can assume an exclusive economic zone (EEZ) 200 miles from their shorelines. Where there is less than 400 miles between any two states, an agreement like the one drawn up between Cyprus and Israel must be made.
The new border puts Leviathan and Tamar firmly within Israel's EEZ, but Turkey – which has occupied northern Cyprus since 1974 – has protested against the agreement, saying it will not recognise it until a solution is found to share the island.
Israel could also face pressure from Lebanon. There, some Hizballah elements in the government have claimed that Tamar and Leviathan stretch into Lebanese waters. Israel denies this claim, as well as saying no third country can have a say in its bilateral agreement with Cyprus.
In January, Delek made a formal proposal to the Cypriot government for joint co-operation in the development of a multi-purpose, liquefied natural gas export plant on Cyprus. Under a possible agreement, Delek would supply gas from the Leviathan and Tamar fields and has suggested that any gas sourced offshore Cyprus could also be processed and exported from the plant.
Even if – in the face of investment worries and political tensions – Israel does manage to bring Leviathan on stream and become a gas exporter, it will face a potentially larger hurdle: the global gas glut could continue for the next decade.
As well as being a vital transit country for Caspian oil and gas, Turkey has long-held ambitions to unlock its Black Sea oil resources, which it says could amount to around 10bn barrels. Turkey is a net energy importer, sourcing around 90% of the oil and gas it uses from overseas, but the government claims the country could be self-sufficient by 2023.
There is some scepticism among analysts about the government's estimation of the oil potential. But it seem as if the majors see possibilities. Turkey's national oil company, TPAO, is working with ExxonMobil, Chevron and Brazil's state-controlled Petrobras across five Black Sea blocks.
"Convincing ExxonMobil to invest means that Turkey has created real momentum," says Andrew Neff, of an analyst at IHS Global Insight. "ExxonMobil wouldn't be there if it didn't see genuine upside," he adds.
ExxonMobil is evaluating two Black Sea prospects in partnership with TPAO, in blocks 3921 and 3922. It will start drilling in 3921 this year, once Transocean's Deepwater Champion drill ship has been delivered.
Petrobras signed a partnership agreement for the exploration of block 3922 with TPAO and ExxonMobil in January 2010. Petrobras, as operator, is now drilling the Sinop-1 well, and signed a memorandum of understanding with TPAO in May 2010 to expand its deep-water activities in the region.
Chevron is the latest to buy into the play, in September 2010, taking a 50% stake in the western part of block 3921 with TPAO as initial operator. One well is being drilled this year, with another to be drilled in 2012