Differing perspectives on the African exploration & production scene were offered during IP Week in London last month, with Tullow Oil and Afren describing their respective approaches to the continent and Equatorial Guinea's energy ministry updating the republic's offshore developments to date. Meg Chesshyre listened in.
Africa is a prolific yet underexplored continent,' Angus McCoss, Tullow Oil exploration director, told delegates at the African session of the Energy Institute's 2011 International Petroleum Week. ‘It is a core continent of activity for Tullow Oil. We are focusing very much on Africa and the Atlantic margins.' Tullow is investing for exploration-led value growth, he added.
Tullow achieved an 83% global exploration success rate in 2010, down to ‘perhaps a bit of Irish luck', but in large part down to good teamwork and a focus on technical excellence in exploration. It has also been very busy acquiring and processing seismic with an eye on building the future portfolio.
It has already had some success in Africa this year with Tweneboa-3, Tweneboa-3 sidetrack, Cormoran, Nsoga-2 and Teak-1.
He made the point that 2003-09 the African industry-wide success declined, despite a 50% increase in drilling. The ‘low hanging fruit' in Egypt, Nigeria, Algeria, Libya, Congo and Angola had been drilled out, but Tullow saw the dawn of a new era of exploration in under-explored African basins and plays.
Tullow's focus is on three main areas – the Mauri-Tano trend, off West Africa (comprising the Mauritania-Senegal, Liberian and Ivorian-Tano deepwater basins), the inland East African rift basins and the East African transform margin. The Ghana programme had delivered some excellent results with five fields discovered since 2007 and a gross resource potential of around 4 billion barrels. The world-class Jubilee field is now producing (OE March 2009), Odum is a potential satellite development, Tweneboa – a significant oil and gas-condensate field, Enyenra – a major new light oil field and Teak – a Campanian-Turonian field up-dip from Jubilee.
Tullow is in the process of expanding the Ghanaian play into the undrilled Liberian basin. The Venus-1 discovery has shown that the Jubilee play extends 1100km from Ghana. Mercury-1 has discovered light oil, with appraisal required. The Cobalt prospect, which is remarkably similar to Jubilee on seismic will be drilled by the Montserrado-1 well later this year. ‘We believe we've got the sweet spots under licence in our acreage, so we'll be extending this play further north into our acreage positions in Mauretania and Senegal,' McCoss explained.
Tullow Oil is also planning a South American campaign this year, pursing the Jubilee play across the Atlantic. ‘If you reconstruct the plate tectonics along the Equatorial Atlantic transform margin, back 90 million years ago, there is a geological correspondence in what we call the Atlantic twin basins.' Tullow has a material offshore acreage position in French Guiana, Guyana and Suriname and is drilling two wells this year – on the Zaedyus prospect offshore French Guiana, and the Repsol-operated Jaguar prospect offshore Guyana, both of which have Jubilee-type attributes, he said.
In the East African transform margin industry is generally focused on the gas potential, but Tullow is pursuing a more elusive light oil opportunity. ‘It will be technically more difficult to achieve this, but we see much higher value in oil than in gas. Typically for contracts in Africa we would see oil being valued about three to six times more than gas, simply due to the longer lead times for gas developments and the high levels of gas infrastructure required.' Tullow is pursuing light oil plays offshore Tanzania and Madagascar, where it sees good potential in the Karoo rift basin play. ‘These are frontier exploration terrains,' noted McCoss.
Take your partners
Afren, established in late 2004, has a business model predicated on partnering with local indigenous companies, national oil companies and governments, Afren associate director Galib Virani told IP Week delegates. It now has 27 assets across nine African countries. Production from the Nigerian Ebok field, due onstream this quarter, should mean that Afren will exit the year with production of about 55,000b/d. Virani stressed that an important part of Afren's model was a high emphasis on community development and local employment.
In Nigeria it has invested about $1billion in capital through its partnerships to date. ‘What we are beginning to see now in Nigeria is a secondary market developing, similar to the Gulf of Mexico or the North Sea some 20 years ago, where a smaller independent like Afren is able to come onto a field and reactivate the field through this partnership approach,' he explained
Virani cited three Afren case studies. The Okoro Setu field, in OML 112 offshore southeast Nigeria, is Afren's maiden greenfield field. A financing and production sharing and technical services agreement was signed with Amni, an established indigenous oil and gas company, for participation in the field in June 2006. First oil was achieved in just two years from entry. There are seven development and one appraisal wells producing through an FPSO and an unmanned wellhead platform. Production continues at around 16,000b/d gross. Infill drilling currently under way is expected to add another 3000-5000b/d.
The Ebok field is an undeveloped oil field located in OML 67, discovered by Exxon in 1968, and awarded to indigenous operator Oriental under the 2007 marginal oil fields awards. In March 2008, Afren signed a farm-in agreement with Oriental to participate in the development of Ebok. Under the terms, Afren is responsible for funding all the capital and operating costs for the field. A three-well appraisal campaign more than quadrupled 2P gross reserves to more than 1000 million barrels. The first two development phases are expected to be producing around 35,000b/d by the end of June.
According to Virani, the successful partnership at Ebok has created follow on opportunities at the adjacent Okwok field, which is a potential commercial development, and OML 115, currently more of an exploration prospect, and there is potential for significant joint development synergies.
The third case study is Afren's partnership with First Hydrocarbon Nigeria (FHN), where Afren has a 45% stake. This is a company that fulfills the Nigerian government's criteria for indigenous operators, and the vision here is for FHN to become a champion in Nigerian indigenous space. The ambition is to list FHN by 2014 establishing a secondary market in Nigeria's E&P;sector. Afren will provide FHN with technical, financial and management support as a technical services provider.
Virani said that Afren had been able to distinguish itself, particularly in Nigeria, by accessing 2P barrels at a relatively low cost. ‘On average over the last five years we've paid approximately $2.50-3/bbl for 2P reserves, which typically in a competitive process would cost in excess of $10-12/bbl.
Gabriel Nbega Obiang Lima, minister delegate in the Republic of Equatorial Guinea's ministry of mines, industry & energy, outlined his country's latest offshore developments and activities. Total Equatorial Guinea production was currently running at 415,000boe/d from the Zafiro complex, the Alba field, the Okume complex and the Ceiba field, he noted.
First production from the Noble Energy-operated Aseng development in block I was estimated to commence by mid 2012. The development would include five subsea production wells tied back to an FPSO, currently under conversion in Singapore, three water injectors and two gas injectors. ‘Over the life of the project the company expects to recover gross hydrocarbon liquids of about 100- 120 million barrels,' said Lima. ‘Aseng also contains an estimated 450-550bcf of gas. This will be produced as part of a new integrated gas monetisation project, once the pressure maintenance phase is completed.'
In January, the ministry announced approval for Noble Energy's $1.6 billion Alen field development plan in block O. First production from the field is looked for by the end of 2013 at a rate of 40,000b/d of condensate exported to the Aseng FPSO and gas production of up to 440mmcfd from 2014, again as part of the gas monetisation programme. There will be three production wells and three gas injectors. The field will be developed with additional capacity to process stranded gas not just from Equatorial Guinea, but also from neighbouring countries. OE