A Decade of Conjugate Margin Exploration
The discoveries of Tupi and Jubilee heralded a decade of ‘conjugate chasing’, covering 15 basins in the deep waters of the Equatorial and South Atlantic. If we compare the results of this exploration campaign in conjugate basins across the area, can we answer the crucial question: ‘if a margin is conjugate is it therefore an analog?
Exploration of the Cretaceous plays in the deepwater equatorial and southern Atlantic can be traced back to pre- and post-salt discoveries made in the late ’90s in the Kwanza and Rio Muni Basins, located in Angola and Equatorial Guinea respectively.
The finds that kicked off a decade of intense exploration, however, were undoubtedly Tupi, the Early Cretaceous pre-salt carbonate discovery in the Brazilian Santos Basin in 2006, and the Jubilee discovery, which opened the Late Cretaceous turbidite play in the Tano Basin in Ghana in 2007.
The Tana Basin, Ghana
In the four years following the play-opening Jubilee discovery, 1.5 Bboe (70% of the total volume to-date) was discovered in a series of commercial discoveries, including the Tweneboa, Enyenra and Ntomme (TEN) cluster of fields and the Sankofa-Gye Nyame fields. The Tano Basin was emerging as a significant petroleum province. By the end of 2011, four more wells had been drilled further along the West African Margin in the Sierra Leone-Liberia Basin, resulting in three non-commercial discoveries. The first test on its conjugate margin in the Foz do Amazonas Basin was also a discovery at Zaedyus, which initially looked promising, but turned out to be non-commercial after appraisal. These disappointing results were an early indication that commercial success outside the core Tano fairway was not a given.
Brazilian Conjugate Margin
A breakthrough for the Late Cretaceous turbidite play came with the play-opening Barra discovery in 2011 in the Brazilian Sergipe-Alagoas Basin.
Meanwhile, by the end of 2011 the pre-salt carbonate play had emerged as a major petroleum province with significant discoveries in both the Campos and Santos Basins. The drilling of 41 exploration wells had resulted in 19 commercial discoveries with a total 28 Bboe of resources (Figure 2) – 90% of the total volumes discovered to date in the play on the Brazilian margin.
African Conjugate Margin
In 2012 the attention moved from the Campos to its African conjugate off Angola, with the Cameia discovery opening the deepwater pre-salt play in the Kwanza Basin. Cameia was followed by a further 23 exploration wells in the basin and the discovery of 2.6 Bboe of resources but with a lot more gas than had been expected. Meanwhile, the early successes of the turbidite play in the Tano and Sergipe-Alagoas Basins were not repeated in other basins along the margins. In fact, between 2013 and 2017, 40 exploration wells were drilled in the turbidite plays on both sides of the Equatorial and South Atlantic at a cost of $3.5 bn, but delivered only one commercial discovery in the Tano and one in the Sergipe-Alagoas. The play concept was proven successful further west in South America at Liza in the Surinam-Guyana Basin – but that has its conjugate in North America rather than Africa (see Figure 1).
Symmetrical Exploration Performance
Some conjugates show some symmetry in exploration performance (Figure 3). Both the Foz do Amazonas and Sierra Leone-Liberia Basins, for example, delivered modest-sized, sub-commercial discoveries. The Campos and Kwanza Basins both have a working pre-salt petroleum system, but the Kwanza contains a lot more gas. Successes in the African Tano and South American Santos Basins were not replicated in the Barreirinhas and Namibe Basins, their respective conjugates. The conjugate of the Sergipe-Alagoas in Equatorial Guinea and North Gabon has not yet fully been tested.
Asymmetrical Exploration Performance
What are the geological factors driving the asymmetry? To determine these, we need to look in more detail at some of these conjugate margins.
In total, 26 Bboe have been discovered in the pre-salt carbonate play of the deep water Santos Basin. In contrast, whilst Early Aptian pre-salt carbonates are exposed onshore in the Namibe Basin, the pre-salt play has not been proven offshore there.
The asymmetric rift and breakup dictated the geometry of the basins, creating an asymmetrical play across the conjugates. The Santos Basin is one of the widest basins in the South Atlantic, characterized by a very broad zone of stretched and thinned continental crust. Success in the Santos has been focused around a large, broad topographical feature called the ‘Outer High’ (Gomes et al., 2009). Its size and position in the basin is the primary control on the scale of the play in Santos, optimal for development of thick carbonate reservoirs and acting as a focus for hydrocarbon migration. In contrast, the Angola-Namibia margin is much narrower and a feature of the scale of the Outer High is simply not present within the Namibe Basin.
Moving further north in the South Atlantic, some symmetry can be observed between the Campos and Kwanza Basins. Reservoir quality rocks are deposited on both margins and the traps have comparable size distribution, as shown on the probability of exceedance curves for the two basins, both of which have a P50 of around 260–280 MMboe (Figure 4).
A major difference between the two margins is the nature of the hydrocarbons found. About 80% of the 5.2 Bboe discovered to date in the Campos is oil, while half of the Kwanza Basin’s 2.6 Bboe is gas. This asymmetry is believed to be a result of the maturation history, with evidence of variations in heat flow between the two basins. The Angola discoveries are located in an area where the crust is thinned and the rise of the asthenosphere during rifting introduced a high heat flux. The syn-rift heat spike was responsible for early maturity of the pre-salt oil-prone source rock. Geochemical modeling, based on Cameia-1 well data, indicates that source rocks located in the pre-salt section have been generating and expelling hydrocarbons since at least 120 million years before present (Cazier, 2014). A Late Cretaceous postrift volcanic event added additional heat flux, possibly cracking oil present in reservoirs to gas and adding CO2 to many of the accumulations in the Benguela sub-basin (Baudino, et al., 2018).
There is a distinct asymmetry in the performance of the Late Cretaceous turbidite plays in the Barreirinhas and Tano conjugates. Between 2007 and 2017, just three wells were drilled in the Barreirinhas, which has delivered only non-commercial gas, whilst 42 were drilled in the Tano resulting in the discovery of 2.1 Bboe of commercial hydrocarbons, 80% of which is oil.
The primary cause of the asymmetry between these conjugates can be attributed to post-rift evolution. A thick Tertiary overburden is present in the Barreirinhas Basin due to the uplift of the Andes in the Miocene. The high volumes of Tertiary sediments deposited into the basin pushed the source rocks deeper into the gas window and also caused extensive gravitational collapse, which has implications on timing of trap formation and preservation. By contrast, in West Africa the Tertiary rivers were diverted away from the Tano area, ultimately creating the Volta and Niger rivers.
Analogous Play Elements
From this analysis of the Cretaceous plays present in the main South Atlantic basins, it appears that for a conjugate basin to be an analog, all of the play elements must be similar, and this is clearly not the case.
Figure 5 summarizes the elements involved in the Equatorial and South Atlantic Cretaceous plays at difference stages of the rift process and why some prove to be analogs and others do not. Marine source and seal deposition, for example, are usually related to regional scale flooding events and can therefore be present on both sides of the Atlantic, although there might be variation on source quality at a local scale.
The depositional processes involved in creating carbonate and sandstone reservoir rocks are comparable, but the presence and quality are not uniform, due to both the asymmetry of the rift and the different provenance of the sediments. Maturation history, by contrast, is usually not analogous because of local variations in the thickness and composition of the crust, overburden and post-rift heat flux.
De-Risking Conjugate Plays
Major discoveries often tempt explorers into extrapolating a play from one flank of a rift into its conjugate margin. The experience in the last decade on the southern and equatorial conjugate margins shows that this must be done with extreme care.
Reconstruction of the regional tectonics and rifting history is necessary to identify the play elements that are common to both sides. Local scale basin evolution makes some play elements unique to a basin, so a conjugate analog would not be valid. Asymmetrical exploration success mirrors the asymmetry of the rift itself.
The key is to understand first what controls success in a play before extrapolating effectively from one side of a rift to its conjugate.
Is a Conjugate Margin an Analog?
So, the answer to the original question ‘is a conjugate an analog?’ appears to simply be: ‘rarely’.
Further Reading on Conjugate Margins
A selection of GEO ExPro articles similar in content or related to conjugate margins in the exploration and production of oil and gas.
Mr. Conjugate Margin
Early in his career, geologist Dr. Webster Ueipass Mohriak analysed 'the whole crust' along Brazil's continental margin to become one of the world's leading experts on conjugate margins.
This article appeared in Vol. 10, No. 2 - 2013
Exploration of The US Atlantic Margin
Vsevolod Egorov; GeoExpera
Covering an area roughly the size of California and Texas combined, the US Atlantic margin is underexplored, but prospective basins along the margin may once again be open to exploration.
This article appeared in Vol. 15, No. 2 - 2018
The Geochemist’s Tool Box
Patrick Barnard, Ian Cutler and Helen Kerr, APT
The conjugate petroleum systems of the North Atlantic, finding hydrocarbons and developing the assets - all viewed through the oil-stained spectacles of geochemistry.
This article appeared in Vol. 13, No. 6 - 2016
Angola, Kwanza Basin: Exploring Further and Deeper
Gregor Duval, Jaswinder Mann and Lauren Houston, CGG
Sub-Salt Plays of the Ultra-Deep Water.
This article appeared in Vol. 10, No. 6 - 2015
New Deepwater Frontiers an Ocean Apart
Marcio Rocha Mello, Nilo Chagas Azambuja Filho, André Bender, HRT Oil & Gas, Silvana Maria Barbanti, Tikae Takaki, IPEX, Carlos Alberto Fontes, GeoHub, Webster Mohriak, Consultant, WMGC
Large oil finds in the African Equatorial Margin have led to recent oil discoveries along the South American Equatorial Margin. Similar geologic and geochemical characteristics suggest analogous petroleum systems with enormous potential in both conjugate margins.
This article appeared in Vol. 10, No. 2 - 2013