Growth and Future Prospects of Central Atlantic African Exploration

Growth and Future Prospects of Central Atlantic African Exploration

27th April 2016

A long history

Historically the Central Atlantic African continental margin has shown much promise for the development of hydrocarbon plays and discoveries, since the early discovery of small onshore gas fields in Senegal in the early 1960s, small offshore oil fields in Benin in the late 1960s, and larger, but sub-commercial heavy oil offshore Senegal, also in the late 1960s.

Despite this early proof of viable petroleum systems and subsequent steady exploration activity, significant developments have been slow to arrive. However, following recent exploration success, and release of key information by the relevant operators on the status of their exploration and development programmes, Gaffney, Cline & Associates (GCA) has undertaken a review of the Central Atlantic African margins to synthesise the available non-proprietary data and information to identify likely future exploration trends.  

This article also appeared in GEOExpro magazine in June, 2016:

The key questions are:

      - Has the discovered resource base realised earlier expectations?
      - What is the likely scale of potential resource growth?
      - What are the key constraints and technical risks?

We have considered two main areas (Figure 1):

      - Passive Margin comprising the Senegal-Bove and Liberia sedimentary basins (Mauritania to Liberia) and
      - Transform Margin comprising the Cote d’Ivoire and Keta-Togo-Benin sedimentary basins, (Cote d’Ivoire to western Nigeria).

Although distinct in their geological histories, both areas have in recent years been rejuvenated by exploration programmes targeting novel structural and stratigraphic plays in Cretaceous and Tertiary sandstone.  Carbonate plays in the Jurassic have also been addressed by recent exploration on the Moroccan margin, and there is deeper upside in the syn- and pre-rift sections; although these remain of interest, they are not addressed here.

Recent developments

Recent E&P activities have inevitably been cautious in the current economic climate but there are significant ventures that ensure that the area remains one of focus. Of note are: the start-up of the TEN development in Ghana by Tullow and partners, slated for mid-2016; appraisal of the Tortue West gas discovery by Kosmos in Mauritania/Senegal and proposed exploration of the same Albian-Cenomanian fairway in a nearby prospect; and further appraisal of the Albian SNE-1 &-2 oil discovery in Senegal by Cairn, with additional targeting of supplementary pools in superjacent Cenomanian reservoirs, drilled by the recent BEL-1 well.

Figure 1: Location of principal oil and gas fields and total sedimentary isopach (km) 

Geological highlights

Mauritania to Liberia Passive Margin

The approximate sedimentary isopach in Figure 1 reflects both the position of early rift basins and, especially, the localisation of the later deltaic depocentres which control reservoir occurrence, and burial and maturation of source rocks. Reservoir distribution is also affected by the uplift, rotation and erosion of the shelf edge during Late Cretaceous times, especially in the centre and south of the area, where this feature leads to a distinct assemblage of hydrocarbon plays (Figure 2). These processes created a steep bypass zone that led to reservoir sandstone deposition in deeper water settings during sea level lowstands. Erosion also created channels and canyons that both localised subsequent sandstone deposition, and resulted in truncation of underlying rocks that influenced trap formation.

Figure 2: Schematic cross-section through Passive Margin, showing main play types (approximate location in Figure 1) (updated after Davison, 2005 and Brownfield and Charpentier, 2003)

Cote d’Ivoire to Western Nigeria Transform margin

The regional sedimentary isopach in Figure 1 shows the location of localised depocentres corresponding approximately to the kitchen areas between the major strike-slip/fracture zones, and suggests that the viable exploration fairway is likely limited by the depth of burial and maturity of the source rocks. Thick sedimentary section is mapped as extending into deep water (> 3000m), in areas inferred to be transitional continental and oceanic crust, with consequently lower levels of predicted thermal maturity. The main plays are stratigraphic and combined structural-stratigraphic traps, relating to the partly inverted and modified transtensional faulting (Figure 3).

Figure 3: Schematic cross-section through Transform Margin, showing main play types (approximate location in Figure 1) (updated after Brownfield and Charpentier, 2006)

Past and future trends

The course of exploration in Central Atlantic Africa is depicted here via “pseudo creaming curves” which show the historical growth of cumulative, potentially recoverable resources assigned to each of the major “play groups” compared to the number of exploration wells drilled (Figures 4 and 6), and the distribution of discovered pool sizes are shown in Figures 5 and 7, as a means of comparing the plays and their historical development. All data are shown with all hydrocarbon phases reported in MMBOE. This is a simplification, but it is sufficient to show the general trends. Key discoveries in the plays’ development are identified on the graphs, and on the location map. They record the innovation in play concepts along with the growing capabilities to operate in the water depths of the continental slope; only six wells were drilled prior to 2000 in water depths greater than 500m, but recent drilling has exceeded 2,700m water depth in both Passive and Transform Margin areas.

Passive Margin        

Tertiary plays are dominated by the heavy oil Dome Flore and associated fields in Senegal, with a smaller population of plays that form the recent discoveries. There seems little potential for additional resource outside the main Tertiary deltaic depocentre, and the tailing off of discovery size is expected to continue, due to localised reservoir distribution and also reliance on vertical migration routes associated with salt piercements (e.g. Chinguetti). In contrast, the older reservoirs have shown an acceleration of growth of resource volumes since the early Pelican and Faucon discoveries, driven by recognition of a suite of plays associated with the Upper Cretaceous shelf edge, especially in the centre of the area. Future significant resource growth is expected in the Maastrichtian-Campanian basinal play (e.g. North Fan), with potential for discoveries on a scale comparable to the largest of those yet discovered. Principal risks are in the definition of the stratigraphic component of trapping and in the demonstration of viable migration pathways. There is potential for further exploitation of the Albian to Turonian plays, although discovery size is expected to be less than the recent major discoveries (e.g. Tortue, SNE) and to diminish in future. The combination of seismic attribute and AVO analysis has proved successful in exploiting the gas play, but trap and reservoir definition may prove more challenging in exploiting smaller, oil-filled traps.

Growth in the hydrocarbon volume base has greatly exceeded the USGS predictions (2003) of Yet-to-Find (YTF). Actual additions since 2003 of 3,702 MMBOE are more than 13 times the median estimate of undiscovered recoverable resource at that time. This increase results from recognition of multiple hydrocarbon source kitchens, beyond the then established Turonian-Cenomanian mudstones, and of new reservoir-seal couplets as the basis for hitherto unrecognised plays.

Figure 4 “Pseudo creaming curves” and exploration drilling history, Passive Margin Basins

Source:  Wood Mackenzie, augmented and analysed by GCA

Figure 5 Hydrocarbon pool size distributions, Passive Margin Basins

Source:  Wood Mackenzie, augmented and analysed by GCA

Transform Margin

Turonian-Cenomanian (middle Cretaceous) reservoirs have driven recent resource growth, in combined structural/stratigraphic traps (e.g. Jubilee, TEN Group) and in structures near the fringes of the play fairway (e.g. Ogo). Additional significant growth is possible but may be limited to the existing kitchen areas. There has been some recent growth in the resource associated with the Upper Cretaceous (Maastrichtian-Campanian) play but this may be restricted in extent by localised migration routes around significant reactivated fault trends and/or close stratigraphic proximity of overlapping sand systems, and the technical and commercial constraints imposed by water depth. Lower Cretaceous plays are unlikely to yield discoveries larger than the Baobab field, which stands out in the pool size distribution. However, there have been recent discoveries in deeper water in structures directly associated with the major fracture zone which may possibly reinvigorate this play.

The resource base has slightly exceeded the YTF predicted previously by the USGS (2006), where median undiscovered (in 2006) recoverable resources were estimated to be 2,628 MMBOE, compared to actual reported recoverable resource growth since that time of 3,163 MMBOE. 

Figure 6 “Pseudo creaming curves” and exploration drilling history, Transform Margin Basins

Source:  Wood Mackenzie, augmented and analysed by GCA

Figure 7 Hydrocarbon pool size distributions, Transform Margin Basins

Source:  Wood Mackenzie, augmented and analysed by GCA


The study area is one with a long exploration history, where recent successes have reinvigorated exploration interest through increased play diversity.  There remain future prospects of resource growth, especially in the Passive Margin basins. Relatively attractive fiscal and contractual terms have played a part in making the area one of successful focus for a small group of independent oil companies.


Brownfield, M.E. and Charpentier, R.R., 2003. Assessment of the undiscovered oil and gas of the Senegal Province, Mauritania, Senegal, The Gambia, and Guinea-Bissau, Northwest Africa, USGS Bulletin 2207-A, 26pp.

Brownfield, M.E. and Charpentier, R.R., 2006. Geology and total petroleum systems of the Gulf of Guinea Province of West Africa, USGS Bulletin 2207-C, 32pp.

Davidson, I, 2005. Central Atlantic margin basins of North West Africa: Geology and hydrocarbon potential (Morocco to Guinea). Journal of African Earth Sciences. V. 43, p. 254-274.


Growth and Future Prospects of Central Atlantic African Exploration

Dr Nick Stronach

Senior Advisor: Geoscience -

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