Discoveries of new elephantine deposits of hydrocarbons in South America and East Africa in recent years have tended to overshadow developments along Africa’s oil-producing Western coast, but new discoveries in deep offshore areas along the coast of countries like Ghana, Nigeria, Gabon and Equatorial Guinea offer significant promise. While OPEC’s two sub-Saharan members, Nigeria and Angola, still dominate production on the continent, the International Energy Agency (IEA) forecast a long-term decline in sub-Saharan Africa’s non-OPEC output from 2.3m barrels per day (bpd) in 2012 to 2.1m bpd by 2035, due in large part to maturing onshore production in countries like Gabon. New seismic and drilling technology able to pierce deep layers of salt in the Gulf of Guinea, first developed in Brazil’s deepwater offshore in the past five years, hold the promise of boosting reserves and output in those markets – albeit at a significant cost.
The success of the Brazilian discoveries has raised interest in developing similar “pre-salt” areas in the lower Gulf of Guinea basin, particularly along Angola, Congo-Brazzaville and Gabon. Similarities across the continental plate could go deeper yet, with discoveries along Equatorial Atlantic Transform Margin, including offshore finds in Ghana and Côte d’Ivoire, pointing to potential deposits along Brazil’s northern Atlantic coast. While holding much potential, any exploitation of these new deposits in deepwater offshore fields requires high international pricing to be commercially viable. The results of drilling campaigns in 2014 and 2015 are thus paramount to better quantifying this potential and ensuring feasibility of production.
Improvements in seismic imaging technology in the past decade have allowed deep-pocketed exploration firms to peek below the layers of salt and rock, traditionally impossible given salt’s distorting impact on seismic waves and older imaging techniques. Brazil launched prospecting in its deepwater offshore as early as 2000, searching particularly for pre-salt hydrocarbons, referring to reservoirs of oil and gas trapped in rock that was subsequently covered by layers of salt. Such deposits sit below up to 2000 metres of hard rock and another 2000 metres of salt at depths of up to 3000 metres of water, contributing to extremely high exploration costs. Compared to costs for drilling onshore, which can be as low as $15m per well, and deepwater offshore, as high as $100m per well, drilling costs for pre-salt are significantly higher in the $ 120m200m per well range, according to Brazil’s state-owned oil company Petróleo Brasileiro (Petrobras).
Brazil’s first major pre-salt discovery came in 2007, when Petrobras and its foreign partners, British Gas (BG) and ExxonMobil, found the Tupi oilfield some 300 km offshore the southern city of Santos and roughly 7300 metres below sea level. The BG-operated block in the Santos Basin cost $250m to drill, yet discoveries of between 6.5bn and 8bn barrels of recoverable reserves, one of the biggest in 30 years, and a well capable of producing up to 20,000 bpd were significant rewards. Several more Santos-basin fields were discovered following Tupi’s discovery and include: Sugar Loaf field, identified in December 2007 with up to 33bn recoverable oil barrels; the Jupiter natural gas field, of similar size to Tupi and found in January 2008; and the Libra field, with up to 7.9bn barrels, located in May 2010.
Given the high expenditures needed, the contractual basis for exploitation of these blocks is crucial for ensuring interest from investors. For Brazil to become the world’s sixth-largest oil producer by 2035, as is forecast by the IEA, it will require significant investments, with Petrobras budgeting $237bn in new investments by 2019 alone. While the fiscal regime usually consists of 30-year concessions, the government suspended new block auctions for 2008-13 pending new rules for pre-salt deposits. Under the new framework passed in 2010, pre-salt blocks are developed under a production sharing contract (PSC) with Petrobras, which must hold a stake of at least 30%.
Petrobras is also allowed to develop smaller blocks independently under hybrid contracts granted under a rights-transfer agreement with the Brazilian National Agency of Petroleum, Natural Gas and Biofuels. New local content rules were also phased in, requiring firms to source over 37% of their components (by value) from Brazilian firms. Petrobras has come under close scrutiny for its $237bn programme, although its $1.52bn sale of a 50% stake in its African operations to Brazil’s largest bank, BTG Pactual, in June 2013 should allow the oil company to focus on the pre-salt programme.
Oil producers in the Gulf of Guinea have also watched such developments closely, not only for the massive investments required but also for the prospects that they hint at closer to home. During the Lower Cretaceous period around 125m years ago, South America and Africa were fused into a single landmass known as Pangaea, leading geologists to the “Atlantic mirror” theory, under which the two continents have shared geological features. Whereas oil deposits above the salt layers have evolved substantially as the continents separated, geologists say the salt and rock acted as a seal, protecting geological structures deep underneath. Whereas Brazil only hosts pre-salt formations offshore, West African producers, like Angola, can claim pre-salt deposits both offshore and on, at depths of up to 4000 metres underground.
The continents share two distinct geological structures, according to the IEA. The first runs from southeastern Brazil to the lower Gulf of Guinea (ranging from Namibia to Angola, Congo-Brazzaville and Gabon), while the second, known as the Equatorial Atlantic Transform Margin, runs from north-eastern South America (French Guyana and north-east Brazil) to the upper West African coast (from Mauritania down to Ghana and the Niger Delta). The US Geological Service estimates that the lower Gulf of Guinea could hold pre-salt reserves as high as 14bn barrels of oil and 35trn standard cu feet (scf) of natural gas, while the West Africa Transform Margin, excluding the Niger Delta’s estimated 22bn reserves offshore, could hold an additional 9bn barrels of oil and 42trn scf of gas. But although initial pre-salt exploration on the African continent started four decades ago, with ENI identifying the M’boundi onshore pre-salt oil deposit in Congo-Brazzaville in the 1980s, it was only with recent discoveries in Brazil that larger exploration investments began.
Lower Gulf Of Guinea
Angola quickly emerged as West Africa’s first mover in pre-salt exploration, awarding 11 pre-salt blocks to seven oil majors, such as Total, BP, ENI, ConocoPhillips, Statoil and Petrobras, in 2011. With a pre-salt formation of roughly the same length as Brazil’s at 700 km, Angola focused exploration on the promising offshore Kwanza basin. As early as 1983, US-based Cities Services had identified the first presalt formation in Angola, on its Block 9, while ExxonMobil struck another find on Block 20 in 1996. Both blocks have since been sold to US junior Cobalt International Energy, in partnership with state-owned Sonangol and BP, which has identified a total of five pre-salt oil and gas deposits on Blocks 20 and 21.
The largest discovery came in 2014 when Cobalt found deposits of 400m-700m barrels at its Orca-1 well on Block 20/11. The firm is also developing the Cameia field on Block 21, found in February 2012, ramping up production to 20,000 bpd once output starts in 2017. Danish oil junior Maersk Oil reported encouraging results at its Azul-1 well on Block 23 in January 2012, with potential flow capacity of more than 3000 bpd, although a full appraisal is still pending. While the Cameia and Orca discoveries included large commercial quantities of oil, most others have yet to match that success. Cobalt’s more recent exploration proved disappointing: while two more wells drilled in the fourth quarter of 2013 revealed estimated resources of 700m-1.1bn barrels of oil, the high proportion of gas, 55-65%, could make commercial exploitation unviable.
New drilling is accelerating on the blocks awarded in 2011, with 15 of the 32 wells drilled in 2014 targeting the Kwanza pre-salt basin. While authorities expect offshore pre-salt discoveries to double the country’s current 13bn barrels of proven reserves and boost its 2013 output of 1.8m bpd, they also plan to open exploration for pre-salt reserves onshore, with an auction planned for 10 onshore blocks by the end of 2014. “By the end of 2014 there will be a strong indication of whether the target of doubling Angola’s oil production in 15 years is achievable,” Tako Koning, a geologist at oil consultancy Gaffney, Cline & Associates, told a Luanda conference in October 2013.
Looking Further Afield
Gabon is also opening up new pre-salt acreage offshore, having already been successful in developing onshore and shallow-water, pre-salt deposits. Prospectors have reported seven offshore pre-salt finds since 2010, six of which are in shallow waters and should add over 500m barrels to Gabon’s reserves, according to Ecobank. Although Gabon’s deepwater offshore does not currently produce, the government expects deepwater projects to boost output, which has declined from 370,000 bpd in 1997 to 237,000 bpd in 2013, to some 500,000 bpd over the next decade.
In August 2013 Total, in partnership with Marathon Oil and Cobalt, struck a gas condensate reserve at its offshore Diaba block, indicating suspended liquid oil some 5585 metres below sea level. While its appraisal is ongoing, the discovery hinted at significant pre-salt potential. A handful of junior exploration firms, including Ophir Energy, Vaalco Energy, Tullow Oil, Dussafu Marin, Panoro Energy and Harvest Operations are also conducting pre-salt exploration, but in shallow waters. Results have been mixed, however, after Ophir failed to discover hydrocarbons at the three wells it drilled in 2014 and suspended operations in Gabon in favour of its Equatorial Guinea drilling.
ENI has been more successful, and in July 2014 the firm reported 500m barrels of oil equivalent (boe) of natural gas and condensates at its Nyonie shallowwater block. Meanwhile, in October 2014 Shell reported a natural gas discovery with 200 metres of net gas pay on Block BCD10, which it operates with junior partner CNOOC at a depth of 2110 metres of water and 2953 metres of salt and rock. While new output from such sources will take years to come on-line should discoveries prove conclusive, Brazil’s pioneering of presalt has already generated significant investment in jurisdictions like Gabon and Congo that had previously been categorised as mature.
Some 5bn barrels of new offshore oil reserves were discovered along West Africa’s Transform Margin between 2007 and 2014, driven by a high 65% success rate for exploration drilling, according to research by Chatham House. Chief among these is the 2bn-barrel Jubilee field offshore of Ghana found in 2007, which could hold up to 4.5bn barrels in potential reserves. Other major finds include: the Keta basin in eastern Ghana, the Dahomey basin in Togo, the Seme basin in Benin and the Mont Okitipupa basin in Nigeria – all part of the offshore Transform Margin. Located at 1100 metres below sea level, Jubilee is split in two main fields: Deepwater Tano, operated by UK-listed Tullow Oil, and West Cape Three Points, developed by US-based Kosmos Energy, alongside partners Anadarko Petroleum Corporation and the Ghana National Petroleum Corporation. Output from Jubilee has risen fast, from 45,000 bpd in 2010 to 85,000 bpd in 2012 and 102,500 bpd in 2013, with a target of 120,000 bpd in 2014. Tullow is also developing the neighbouring TEN field at a cost of $4.5bn, with first production planned for 2016. Majors ENI and Hess Corporation have also reported finds in the Sankofa and Tano blocks, respectively, both adjacent to Jubilee.
Finds in Ghana have spurred interest westward, with discoveries in Côte d’Ivoire, Liberia and Sierra Leone providing confirmation of the Atlantic mirror theory. Since 2011 alone, Côte d’Ivoire has hosted three larger discoveries on the offshore Blocks CI-401, CI-103 and CI-100 operated by Vanco, Tullow and Total, respectively. These fields, at depths of over 2000 metres, suggest that Ghana’s western Tano basin spreads to Côte d’Ivoire, even if the country’s proven reserves remain low at 100m barrels of oil and 1.1trn scf of gas.
Exploration in the western Transform Margin in Liberia and Sierra Leone have also yielded encouraging results. “Recent oil discoveries in Sierra Leone confirmed that the main reservoir and source elements in the Jubilee field in Ghana are present in the Sierra Leone/Liberia deepwater basin,” noted a December 2013 report on African oil by the US-based Strategic Studies Institute. Australian junior African Petroleum and Anadarko have been most successful in offshore Liberia and Sierra Leone. The former reported three distinct discoveries offshore Liberia in September 2011, February 2012 and February 2013, while Anadarko found oil in Sierra Leone in November 2010 and February 2012, with additional finds in Liberia in November 2011.
The success of the finds along West Africa’s Gulf of Guinea coast, and comparatively high prices sustaining investors’ enthusiasm for such frontier acreage, has prompted exploration to spread outwards on the other side of the Atlantic as well, yielding some results on the Transform Margin’s South American edge. Tullow was the first to strike oil offshore Suriname in 2011 with its discovery of 840m boe at its Zaedyus-1 block, followed by smaller discoveries by Repsol at Jaguar-1 and CGX Resources at Eagle-1. Yet subsequent drilling programmes in 2012 and 2013 proved inconclusive.
Discoveries in challenging pre-salt provinces offshore of Brazil and in frontier acreage along the West African coast have attracted significant attention on both sides of the Atlantic. While South America and East Africa have yielded elephant discoveries in recent years, new exploration in West Africa shows significant promise. High drilling costs, ranging from $100m per well in deepwater offshore to $ 120m200m per pre-salt well, are prohibitive for all but the highest-capitalised exploration firms. Oil majors involved in pre-salt exploration on both sides of the Atlantic have been raising funds to finance their ambitious work programmes. Downward pressure on light, sweet crude prices, stemming from rising US shale oil production, could make some smaller pre-salt discoveries unprofitable to develop, although the size of Brazil’s large presalt deposits have sufficient scale. With similarities between deepwater provinces in Brazil and the Gulf of Guinea proven, West Africa’s frontier should attract significant upstream investments for decades to come.
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