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Southern Africa: a new exploration hotspot?


Time for Take-Off

Following decades of frustration in offshore exploration along the southern African coast, Namibia and South Africa are now poised to enter a crucial phase in the hunt for hydrocarbons. Tullow’s Cormorant 1 new-field wildcat (NFW), spudded in Namibia’s Walvis Basin on 4th September 2018, and Total’s Brulpadda 1AX re-drill in South Africa’s Southern Outeniqua Basin will kick-start deepwater exploration drilling this year. Many other companies have also been positioning themselves in offshore acreage across both countries, leading to the possibility of a flurry of offshore drilling in the next two years.

The Historical Context

To appreciate the significance of the imminent wildcat drilling, past events, attempts and disappointments must first be understood.

The first-ever offshore well in Namibian waters was the Kudu 9A 1 NFW, drilled by Chevron in the Orange Basin in 1974, encountering the 1.3 Tcf Kudu gas field. Since then, only 21 offshore exploration wells have been drilled along the country’s 1,600km coastline, with the real game-changers being HRT’s deepwater Murombe 1 and Wingat 1 NFWs, drilled in the Walvis Basin in 2013. Despite one being dry and the other non-commercial, the wells served to prove the presence of a working Aptian source rock, producing light oil in a region previously thought to be gas-prone. However, since this significant finding, just one dry well has been drilled, Welwitschia 1 (Repsol), towards the north of the Walvis Basin in 2014. This duster is still the most recent well drilled in the country, with the crash in oil price also playing its part in freezing development in Namibia’s nascent upstream industry.

South Africa has had a more active history of exploration, with over 300 offshore wells drilled since 1969. Other than some initial interest from International Oil Companies (IOCs) in the early 1970s, this drilling activity can largely be attributed to the national oil company (NOC) (previously known as Soekor, now PetroSA). IOCs avoided operations, mainly due to the international boycott of the apartheid-era government. Soekor focused much of its attention on shallow-water off the southern coast; it experienced most of its successes in Block 9 in the Bredasdorp Basin in the 1980s and 1990s. However, the several oil, gas and condensate discoveries made have been small-scale, and production from these fields has long been in decline. Although the shallow waters are well-explored in parts, South Africa’s deeper waters have remained almost untouched; only one well has previously been drilled in >500m water depth. A key reason for this is the extremely challenging metocean conditions, particularly along the east and south coasts, where the very strong Agulhas Current flows down from the Indian Ocean. Total encountered these problems during its first attempt at drilling Brulpadda 1AX in 2014, which incidentally was the last offshore well drilled in South Africa.

Retaining Foreign Investment

Since gaining independence from South Africa in 1990, it can be said that Namibia has adopted a more coherent strategy for running its upstream sector than its neighbour to the south. Although at present it lacks the discoveries to show for its efforts, Namibia has successfully attracted significant foreign investment and its political stability and lenient approach (particularly in terms of extending or modifying work commitments) has ensured that very little of the acreage held by IOCs has been relinquished during the recent downturn. IOCs are also showing new interest in South Africa, with several majors farming-in to offshore licences recently; however, exploration work programmes have been severely hampered by the political upheaval and legislative delays in the country. Companies have been waiting nearly four years for fiscal terms to be clarified through the passage of the Mineral & Petroleum Resources Development Act (MPRDA) Amendment Bill, but in a recent twist, the government is now talking of developing a separate and dedicated legislative framework for the petroleum sector, which will take yet more time to enact.

A common theme linking the two countries is a lack of indigenous oil and gas reserves, and thus a struggle to meet the domestic energy demand. Namibia’s Kudu Field has faced numerous delays in getting sanctioned and is seen by some officials as being a non-viable project. In South Africa, many of PetroSA’s fields in Block 9 are either non-commercial or shut-in, with the NOC struggling to find enough feedstock to supply its gas-to-liquids refinery in Mossel Bay. Both countries are yearning for a first large magnitude hydrocarbon discovery to be made along their vast offshore acreage.


Figure 1 – Historic wells & planned drilling over Namibia’s offshore acreage

Figure 1 – Historic wells & planned drilling over Namibia’s offshore acreage

Cormorant 1

The first well in this new phase of exploration is Tullow’s Cormorant 1 NFW in the Walvis Basin. The Ocean Rig “Poseidon” drillship has been contracted and commenced drilling operations on 4th September 2018. The well is being drilled in 545m water depth (WD) in the western half of block 2012B and is expected to take just over 30 days to reach the 3,830m PTD. It will test the Cormorant prospect, which is a 120 sq km Cretaceous turbidite fan, estimated to possess un-risked prospective resources of 124 MMbo (best estimate). Cormorant was identified from a 3D seismic survey acquired in 2014, along with three additional turbidite fans (the Albatross, Seagull & Gannet North and Seagull & Gannet South prospects) which will provide nearby follow-on opportunities, should Cormorant 1 prove successful. The cumulative un-risked prospective resources across these four fans is estimated at 915 MMbo.

Partners have farmed-in to the licence in advance of drilling; Africa Energy and ONGC Videsh acquired stakes in 2017, joining Tullow, Pancontinental and local company Paragon Oil & Gas. Tullow was also granted entry into the two-year Second Renewal Period of the licence earlier this year, meaning everything is now in place for the upcoming work programme.

Subsequent exploration

The next firm well in line for drilling is Chariot Oil & Gas’ S prospect, scheduled to be drilled by the Ocean Rig “Poseidon” drillship in Q4 2018, after it has concluded operations at Cormorant 1. This well will be drilled in deeper waters (1,650m WD) to the south of the Walvis Basin, in Chariot’s 2312 block. Prospect S follows a similar play concept to Cormorant, involving a Late Cretaceous turbidite reservoir with an Aptian source. Gross mean prospective resources for the four-way dip closed structure are estimated to be 459 MMbo. In the event of a discovery, Chariot also has the option to drill a further well and would look to test the W prospect, another turbidite fan, to the west of prospect S; however, this well would be contingent on Chariot securing a partner first.

The Cretaceous turbidite trend in the Walvis Basin could be explored beyond these two firm wells, with the drilling of the Osprey 1 NFW in Eco Atlantic’s 2012A block. Tullow and ONGC are in the process of acquiring equity in 2012A. Tullow is yet to finalise this two-phase transaction, which would see it become operator and share the well-costs. The decision to move forward with the second-half of this farm-in agreement will depend on the success of Cormorant 1, which is being drilled in the adjacent block to the south.

Looking further ahead, the superrmajors are also looking to get in on the act; Total and Shell both have plans for deepwater drilling in 2019/2020. Shell’s NFW and Total’s ultradeep Venus 1 well will look to explore the Orange Basin to the south, in adjacent blocks 2913A and 2913B respectively.

South Africa

Figure 2 – Planned offshore exploration by supermajors & Africa Energy in South Africa

Figure 2 – Planned offshore exploration by supermajors & Africa Energy in South Africa


Brulpadda 1AX

Moving to the south coast, all eyes will be on the re-drill of Total’s Brulpadda 1AX; the NFW should be re-spudded in the Southern Outeniqua Basin in December 2018. Brulpadda 1AX is to be drilled in the south-west corner of Total’s Block 11B/12B, in 1,431m WD. Total first attempted this in 2014, during South Africa’s winter months, but due to the strong currents and harsh conditions, the rig had difficulty in spudding the well and was eventually forced to abandon operations, after only having reached around 400m below the mud line. This time, Total will be drilling during South Africa’s summer months and has contracted the Odfjell Drilling “Deepsea Stavanger” semi-submersible rig for the job, which has operational capability in harsh environments. If operations run smoothly, the well is expected to take between 60-80 days to reach its target depth of ~3,500m. Brulpadda 1AX will aim to test an Early Cretaceous turbidite fan, as well as a deeper secondary objective. Brulpadda, or Bullfrog, is one of five AVO and DHI-driven oil prospects, identified from 2D seismic in the post-rift Paddavissie Play Fairway and estimated to possess a combined 3 Bbo un-risked prospective resources. The most likely of these basin-floor fans to be drilled back-to-back to a Brulpadda discovery would be the Leopard prospect to the east, as this is also thought to possess a deeper, secondary reservoir target. Reservoir analogues can also be found in the shallow-water PetroSA fields (mentioned above), situated in the same source kitchen in the adjacent Block 9, which is oil-mature in the mid-Aptian and Hauterivian. The reservoirs in this area of the Bredasdorp Basin are more channelized and are modelled as the sediment source for the Paddavissie fan systems.

As with Tullow in Namibia, Total has been securing additional partners in Block 11B/12B and has also recently been granted entry into the two-year Second Renewal Period of the licence. Current partners Total and Canadian Natural Resources have entered farm-out agreements with Main Street 1549 (49% owned by Africa Energy Corp) and Qatar Petroleum, which are expected to receive approvals soon.

Subsequent exploration

Although Brulpadda 1AX looks certain to go ahead irrespective of any legislative changes in South Africa, other companies may be more hesitant and their future offshore drilling plans are more likely to hinge on the passage of any petroleum-specific legislation. Furthermore, majors with future deepwater drilling plans, such as Eni and ExxonMobil, will be keeping a close eye on proceedings at Brulpadda in the hope that the tough metocean conditions can be overcome. Eni plans to begin deepwater exploration in the 236ER block in 2019 and ExxonMobil is considering wildcat drilling on its Tugela South and Transkei blocks in 2020 and 2021 respectively. All of this acreage lies in the Durban Basin along the country’s east coast, where the Agulhas Current can be even stronger.

Elsewhere in South African waters, Africa Energy is hoping to drill the Gazania 1 exploration well on Block 2B. This would be drilled in shallower waters (~150m WD) in the Orange Basin on the west coast, but a planned spud date of Q3 2019 is reliant on a farm-in partner being found to fund the well.

Questions to be answered

This long-awaited drilling activity is attracting considerable industry interest and will look to provide better answers to some of the burning questions that remain in this frontier area; a key one being whether Namibia and South Africa share the same petroleum potential as the proven basins along the conjugate margins of Brazil and the Falklands Plateau? If this is the case, then it is evident that the deepwater Cretaceous turbidite petroleum plays will be vital, not only in the first round of drilling, but also in follow-on exploration in the years to come. Namibia and South Africa will be hoping that past failures and a four-year drilling hiatus will culminate with the large magnitude, basin-opening discovery that both countries need to invigorate their budding hydrocarbon sectors.

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Jimmy Boulter

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