Thematic set:

Tectonics and petroleum systems of East Africa Petroleum Geoscience

Published Online First https://doi.org/10.1144/petgeo2017-028

Geology and hydrocarbon potential of the East African continental

margin: a review
Ian Davison1,2,3* & Ian Steel1,2
1
Earthmoves Ltd, 38–42 Upper Park Road, Camberley, Surrey GU15 2EF, UK
2
GEO International Ltd, 38–42 Upper Park Road, Camberley, Surrey GU15 2EF, UK
3
Department of Earth Sciences, Royal Holloway, University of London, Egham, Surrey TW20 OEX, UK
* Correspondence: i.davison@earthmoves.co.uk

Abstract: The East African margin has a complex structure due to multiple phases of rifting with different stretching
directions. The main phase of rifting leading to Indian Ocean opening lasted from the Late Pliensbachian to the Bajocian
(c. 183 – 170 Ma). This occurred during impingement of the Bouvet hotspot which weakened the lithosphere sufficiently to allow
continental break-up. Thick salt and marine shales were deposited during the Toarcian in the Majunga, Ambilobe and Mandawa
basins and the onshore Ogaden Basin; marking the onset of the Indian Ocean marine incursion, when good quality oil-prone
source rocks were deposited at this time. The recent giant gas discoveries in Tanzania and Mozambique are believed to be sourced
from overmature Jurassic or, possibly, deeper Permian age Karoo shales. The margin from the Lamu Basin in the north to the
Zambesi Delta in the south is covered by thick Tertiary and Cretaceous sediment derived from the East African rift shoulders, and
Lower Jurassic source rocks are predicted to be in the gas window along most of the margin. However, the margins in South
Africa, south Mozambique, northern Somalia and Madagascar are less deeply buried, and have better oil potential.
The large Tsimimo and Bemolanga tar sand deposits and the recent announcement of an oil rim in the Inhasorro Field indicate
that there are good oil-prone source rocks in the Karoo rifts and in the Albian Domo shales; and the search for oil continues with
companies exploring in areas where Jurassic source rocks may be less deeply buried, and/or potential Albian–Turonian-aged
source rocks are sufficiently buried to generate oil.

Supplementary material: Figures S1–S3 are available at: https://doi.org/10.6084/m9.figshare.c.3894931

Received 6 March 2017; revised 7 September 2017; accepted 11 September 2017

Hydrocarbon exploration was fairly limited along the East African • Early Cretaceous rifts (Xai-Xai and Palmeras in the south,
margin until 2010, with less than 60 offshore wells drilled before the and the Anza and Maridadi in the north), both trending NW–
major gas discoveries in the Rovuma Delta and Mafia Basin. There SE; exact ages are not known and it is not clear whether these
has been a flurry of exploration activity since, resulting in the were caused by the same event (De Buyl & Flores 1986).
discovery of more than 200 Tcf (trillion cubic feet) of recoverable • Late Cenozoic offshore rifts (c. 5 – 0 Ma; Querimbas and
gas reserves. This has led to large numbers of detailed papers and Lacerda rifts, which are an extension of the East Africa Rift
company presentations on the margin. This paper reviews this vast System) (Franke et al. 2015).
array of public domain information and attempts to summarize the
The margin is also further complicated by Jurassic rifting having
geological evolution of the East African margin, including the
occurred obliquely to the margin followed by seafloor spreading
Seychelles and the west coast of Madagascar, and briefly assesses
which opened north–south, creating transform and transtensional
the hydrocarbon potential (see Fig. 1 for the area covered).
zones of late rifting (see the Supplementary material).

Tectonic history of East Africa Karoo rifting phase (Carboniferous–Early Jurassic)

Rifting events Pan African age (c. 1000 – 550 Ma) mobile belt weaknesses exerted
a strong control on the orientation of the Karoo rifts in the onshore
The East African margin had a complex rifting history during at
area (Fig. 2). The location and orientation of the offshore Karoo rifts
least five discrete phases which have different trends (Fig. 1):
is still poorly known because they are deeply buried, and difficult to
• Karoo age (c. 315 – 195 Ma, Late Carboniferous–earliest image on seismic reflection data. The major Pan African age mobile
Jurassic) long-lived rifting with variable trends from NE to belts are generally orientated parallel to the East African coastline,
NNW (Catuneanu et al. 2005). and the Karoo rifts can be expected to be coast parallel (Fig. 2).
• Early to Mid-Jurassic rifts (c. 183 – 170 Ma, Late Karoo basins developed in cold arid climates in Late
Pliensbachian–Early Bajocian age; precursor to ocean Carboniferous–Early Permian times, during the foreland basin
spreading) with poorly defined trends, but the Mandawa, development in South Africa, with the climate becoming warmer
Morondava and Majunga basin trends are NE to NNE and wetter in Late Permian–Triassic times during the main Karoo
(Quinton & Copestake 2006; Papini & Benvenuti 2008). rifting phase (Catuneanu et al. 2005). The early Karoo sediments are
• Oxfordian–Valanginian rifts (c. 163 – 133 Ma) in South dominated by glacial deposits, sandstones and shales. Late Permian
Africa developed during southern South Atlantic rifting, coals and some thin organic-rich algal (oil-prone) shales occur
trending WNW oblique to the dextral Agulhas–Falklands throughout the southern rifts of Africa, with two correlatable
Fracture Zone (Beckering Vinckers 2007). organic-rich horizons of Artinskian and Capitanian age (see the

© 2017 The Author(s). Published by The Geological Society of London for GSL and EAGE. All rights reserved. For permissions: http://www.geolsoc.org.uk/
permissions. Publishing disclaimer: www.geolsoc.org.uk/pub_ethics
 I. Davison & I. Steel

Fig. 1. Rift basins along the East Africa margin, colour coded by rifting phase and deltas. East Africa rifts partly from Chorowicz (2005).
 The East African continental margin: a review

Fig. 2. Location of the onshore Karoo age rifting and a simple outline of the Pan-African mobile belt trends, which appear to have controlled the location of
the Permo-Triassic rifts. Onshore oil seeps and offshore slick locations from multiple sources (over 20 papers and some confidential reports).
 I. Davison & I. Steel

Fig. 3. Possible SDRs, volcanic flows and dykes associated with the Bouvet hotspot. Most dyke locations are from Geological Survey of Botswana (1978),
Chavez Gomez (2000), Mekonnen (2004) and Reeves (2000). The section location for Figure 4 is shown.

Supplementary material). There was an important marine trans- • WNW–ENE-trending Okovango (Botswana) dyke swarms
gression at the start of the Triassic in Madagascar which coincides (178 Ma: Le Gall et al. 2002, 2005);
with the initiation of the main Karoo rifting event. The preserved • north–south-trending Lebombo monocline volcanics and
Karoo sequence generally reaches up to 2 – 4 km in thickness coast-parallel dyke swarms (dated at 182.1±2.9 Ma: Riley
(Catuneanu et al. 2005). Many oil seeps and oil shows in wells have et al. 2004; Klausen 2009), and NE–SW-trending Mwenetzi
been reported within the South African Karoo coalfields (Petroleum volcanics and dyke swarms (Jourdan et al. 2004).
Agency South Africa 2008), but very little oil exploration has taken
The Lebombo and Mwenetzi volcanics have been interpreted as
place in the onshore Karoo basins to date (Fig. 2).
seawards-dipping reflector sequences (SDRs) (Klausen 2009;
Davison & Steel 2016), which form a pre-drift conjugate pair
Jurassic rifting and the Bouvet hotspot with the Explora wedge volcanics in Antarctica (Hinze & Krause
The Permo-Triassic Karoo rifting did not achieve break-up of 1982; Kristoffersen et al. 2014). The Lebombo volcanic belt is, on
Gondwana. A hiatus of some 10 myr was followed by the Early average, 35 km wide and lava-bedding dips progressively increase
Jurassic rifting which commenced in the Late Pliensbachian eastwards from 10° E to 40° E due to synmagmatic rotation
(c. 185 – 183 Ma) and ended in the Mandawa Basin by the Aalenian (Klausen 2009) (Fig. 4a). Dyke injection varies from perpendicular
(174 – 170 Ma: Quinton & Copestake 2006), but continued until the to bedding, to 60° to bedding and consistently dipping westwards,
early Bajocian in Madagascar (c. 170 Ma: Besairie 1972). The suggesting synvolcanic rotation has occurred. Up to 50% of the
oldest rift strata in the Majunga and Morondava basins are Early section can be dykes (Fig. 4a) (Klausen 2009). Along their eastern
Toarcian (Besairie 1972), which consist of marine marls and edge, the lavas dip underneath the overlying Lower Cretaceous
limestone and evaporites, followed by Bajocian–Bathonian clastic sediments. Lavas were encountered at 3.2 km depth in the
shallow-marine deposits. It should be noted that the duration and Domo-1 well which lies c. 300 km east of the Lebombo monocline
onset of rifting probably varies along the margin, and there are still exposures (Fig. 4b). The conjugate wedge in Antarctica also has an
only a few areas that have been sampled and dated. It is no estimated width of 220 km (Kristoffersen et al. 2014). Hence, the
coincidence that the Bouvet hotspot developed at the same time as Mozambique plain may be floored by SDRs and oceanic crust (see
the successful rifting that proceeded to break-up. The hotspot also Franklin et al. 2015). SDRs are also present in the Angoche
created a vast system of continental flood basalts, dyke swarms and Basin and east of the Beira High (Fig. 3).
elongate volcanic complexes (seawards-dipping reflectors) com-
posed of the following (Fig. 3): Opening history of the East African Indian Ocean
• Karoo-Ferrar basalt fields in Africa, Antarctica and Australia Initiation of ocean spreading of the West Somali–Madagascar Basin
(183 Ma, Pliensbachian: Duncan et al. 1997); is not clearly defined, and may have started as early as 183 – 177 Ma
 The East African continental margin: a review
Fig. 4 (a) Schematic section through the Lebombo monocline reconstructed using field data collected by Klausen (2009) with a graph of the amount of dyke dilation along the section showing an average of c. 35% (drawn by
authors using data in Klausen 2009). (b) Regional section from the Lebombo monocline to the coastline based on our own work. The line location is shown in Figure 13.
 I. Davison & I. Steel

Fig. 5. Vertical gravity gradient map

interpreted to show the fracture zones and
mid-ocean ridge between Madagascar and
mainland Africa. Gravity data from
Sandwell et al. (2014).

(Eagles & König 2008; Reeves 2016); but may have been as late as if spreading started at 165 Ma and ceased at the M10n anomaly
165 Ma, shortly after the rifting ceased in the Aalenian–early (135 Ma: Norton & Sclater 1979), to 3.5 cm a−1 if spreading
Bajocian in Madagascar (Papini & Benvenuti 2008). The ceased at 118 Ma (M0 anomaly: Segoufin & Patriat 1980). Davis
widespread marine flooding in the Toarcian could be synchronous et al. (2016) estimated that spreading ceased at 120.8 Ma using
with spreading, although localized rifting still may have continued new magnetic data.
after this. The Falklands Plateau of South America fitted snuggly against
The position of the extinct mid-ocean ridge between the transform margin of South Africa until Hauterivian–Barremian
Madagascar and Africa was not easily defined by either gravity times when the South Atlantic Ocean opened. The Agulhas–
or magnetic data as it is buried below a thick pile of sediment Falklands Fracture Zone lies south of the west African marginal
(5 km) and Cenozoic volcanics (cf. Cochran 1988 and Eagles & basins in South Africa, but comes very close to the eastern South
König 2008). However, recent satellite gravity data (Sandwell et al. African margin in the Transkei Basin, which is a true transform
2014) better defines the fracture zones and the mid-ocean ridge is margin. The Transkei has poor hydrocarbon potential because any
clearer (Davison et al. 2015; Phethean et al. 2016) (Fig. 5). The potential Jurassic or Cretaceous source rock would be likely to be
ocean–continent boundary (OCB) positions in Figure 5 have been immature as the sedimentary infill is usually less than 2 km
estimated using the long offset, deep seismic reflection imaging (Schlüter & Uenzelmann-Neben 2008).
(Danforth et al. 2010, 2012) as well as the new satellite gravity The Seychelles and India are thought to have separated from
data. There is approximately 1700 km of oceanic crust preserved Madagascar around 88 Ma, when the Marion hotspot initiated,
between Africa and Madagascar (measured parallel to the fracture which was centred in southern Madagascar (Storey et al. 1995). The
zone trend). Estimates of full spreading rates vary from 5.4 cm a−1, Seychelles and the Mascarene Ridge were separated from India
 The East African continental margin: a review

Fig. 6. Line drawing through the Lamu Basin, Kenya showing a large rift basin of Early Cretaceous age. The Simba-1 well was dry. Interpreted from ION
Geophysical seismic data. The line location is shown in Figure 22.

around 70 – 65 Ma, when the Carlsberg Ridge initiated and the et al. 2001). The Marion hotspot was believed to have been centred
Deccan flood basalt province was formed (Duncan & Pyle 1988; over SW Madagascar, and volcanic ages range from 91.6±0.3 to
Van Hinsbergen et al. 2011; Reeves 2016). After separation, the 83.6±1.6 Ma (Storey et al. 1995; Torsvik et al. 1998). The ages of
Seychelles rotated anticlockwise in the Palaeogene, which caused the magmatism corresponds to the break-up of Madagascar from
plate compression but not necessarily subduction along the India, again suggesting that plume weakening led to continental
Amirante Banks (Eagles & Hoang 2014). break-up.

Early Cretaceous rifting Tertiary rifting

The Lamu Embayment and Maridadi Trough are offshore extensions The East African Rift began to develop soon after the Afar Plume
of the Anza Graben, where the initiation of rifting is dated as volcanics were erupted at c. 30 Ma (Baker et al. 1996). The rift
Neocomian, but extension continued with Cenomanian– propagated southwards, and bifurcated into an eastern and western
Maastrichtian and Early Tertiary rifting phases (Bosworth & branch over the next 20 myr until it finally propagated offshore
Morley 1994; Morley et al. 1999). A section through the offshore (Franke et al. 2015; Macgregor 2015) (Fig. 7). Two branches of the
area in the vicinity of the Simba-1 well in Kenya indicates a well- East Africa Rift extend into the offshore region in Mozambique,
defined fanning stratal wedge attributed to the Early Cretaceous rifting with the eastern branch forming the offshore Pemba–Tembo–
(Fig. 6). The total Jurassic–Early Cretaceous age stratal thickness may Zanzibar trough system and continuing southwards to the
reach up to 10 km in this area. Elsewhere along the margin, Early Querimbas-Lacerda Graben (Mougenot et al. 1986; Franke et al.
Cretaceous rifting also occurred in southern Mozambique with the 2015; Mulibo & Nyblade 2016) (Fig. 1). These graben appear to be
development of the Albian–Aptian age Xai-Xai Graben and several caused by reactivation of the Davie Transform and associated
other parallel half-graben (De Buyl & Flores 1986; INP Instituto subsidiary north–south-trending faults. The western branch of the
Nacional de Petroleos Mozambique 2011) (Fig. 1). East Africa Rift may just be starting to propagate offshore as there is
a concentration of earthquakes located along the offshore
prolongation of the Urema and Chissenga graben in Mozambique
Late Cretaceous magmatism in Madagascar
(Macgregor 2015) (Figs 1 and 7).
Basaltic and rhyolitic lavas and dolerite sills occur throughout The Zanzibar, Pemba and Tembo troughs contain Neogene
onshore Madagascar; and sill intrusions and basalts have been sediment up to 5 – 6 km in thickness, but the exact age of the strata is
encountered in offshore wells in the Morondava Basin (Bardintzeff not known (Kejato 2003; Parsons et al. 2013). The offshore active
 I. Davison & I. Steel

Fig. 7. East Africa Rift System showing the normal faults and earthquake epicentres. Sourced for the NOAA database. Current relative plate motions are
from Calais et al. (2006). The length of the arrows corresponds to the plate speed.
 The East African continental margin: a review

rift segment in the Querimbas Graben, has boundary faults with hotspot is still active, centred over the Grande Comore Island
1.5 km of offset at the seabed; even though this lies at the downslope (Emerick & Duncan 1982). The southern trail initiated around
front of the Rovuma Delta where sedimentation rates are high 30 Ma on the Mascarene Bank and continued to Mauritius, and is
(McDonough et al. 2016). Deformation in this graben is very late currently active on Reunion Island.
with very little evidence of sedimentary growth thickening into the The main geological events that affected the East African
graben until the Pliocene (Franke et al. 2015). The East African Rift margin are summarized in Figure 9. The geology and hydrocarbon
is currently very active along its whole length, and is extending at a potential of the individual basins are now described from south to
rate of 4 cm a−1 in the north and 2 cm a−1 in the south (Calais et al. north.
2006) (Fig. 7).
The shoulder uplift of the East African Rift resulted in a large
Algoa and Gamtoos rifts
amount of denudation from 30 Ma to Recent, resulting in the large
deltas in Somalia, Rufisque (Tanzania) Rovuma and Zambesi Introduction
(Mozambique), and the Tugela Cone (South Africa: Fig. 1). The
Lamu-Juba and Rovuma deltas have well-developed compressional The Algoa and Gamtoos rifts were developed along the Agulhas
toes due to gravity gliding in Late Cretaceous–Late Tertiary times, Transform Zone in Late Jurassic–Early Cretaceous times, when the
whereas the Zambesi and Durban deltas are relatively undeformed, Falklands Plateau of South America separated from the African
with limited extensional faulting and only very localized compres- margin. The rifts trend WNW, and extend onshore into the
sion at the toe. Gamtoos, South Sundays Trough and Northern Uitenhage Trough
(Fig. 10a). Nineteen wells have been drilled by PetroSA (formally
Soekor) in the offshore portions of these basins, all in less than
Tertiary magmatism 200 m water depth. Oil shows were encountered in at least two
wells. Pioneer drilled the Hb-Q1 well in November 2000, and there
Two parallel hotspot trails of Tertiary age are present in the Indian have been no further wells since.
Ocean (Fig. 8). The northern trail extends from the Seychelles to
Grande Comore Island, and even possibly to the outer Rovuma
Stratigraphy
Delta where a circular bulge 300 km in diameter is observed at the
seabed (Sayers 2017). Recent volcanism is also associated with this Rifting commenced in the Oxfordian and continued to the
bulge along the eastern margin of the Querimbas Graben. The other Valanginian, with lacustrine clastics deposited with potential
hotspot trail extends from the Nazarene Bank to Reunion (Fig. 8). source rocks and reservoirs (Thomson 1999). There was a marine
The Seychelles volcanism commenced around 50 – 40 Ma and the incursion at the end of rifting, when shallow-marine clastics were

Fig. 8. Map of the Tertiary volcanic hotspot trails in the western Indian Ocean superimposed on the Sandwell et al. (2014) vertical gravity gradient map.
Ages in Ma are shown in purple boxes from Emerick & Duncan (1982, 1983) and Nougier et al. (1986). The continental ribbon SW of the Seychelles is
also shown.
 I. Davison & I. Steel

Fig. 9. Geological events summary chart for the East African margin.

deposited (Beckering Vinckers 2007). The end of rift unconformity carbon (TOC) and hydrogen index (HI) values up to 500, which are
is overlain by Hauterivian strata. A substantial amount of erosion up to 170 m in thickness (Van der Spuy 1997). The Port Elizabeth
occurred at this time indicating uplift of the shelfal area, which may Trough also contains marine shales of a similar age with 1.3 – 3.5%
have been associated with the impingement of the Etendeka-Paraná TOC and HI of 150 – 440. Excellent quality source rocks have been
plume on the South Atlantic margin. The Algoa Canyon is a major proven in the DSDP wells, which are located on the Maurice Ewing
erosive channel feature that was incised in the Barremian–Aptian Bank. This was adjacent to South Africa from Upper Jurassic to
and filled by Aptian–Albian age clastics (Fig. 10b). South Africa Valanginian times. The DSDP 330 well encountered good source
was uplifted in the Oligocene by a mantle hotspot (South African rocks of Mid-Albian (drift phase), Barremian–Aptian (late rift to
Superplume) which continues to the present day underneath South drift) and Late Jurassic ages with >100 m thickness of marine shales
Africa, with accelerated erosion and clastic deposition in the containing TOC values of 2 – 6% (DSDP 1989).
offshore from 30 Ma to the present day (Burke & Gunnell 2008).
Maturity
Structure
Present-day heat flow in the offshore area is estimated to be around
This is a dextral transtensional margin which opened up with right- 45 – 55 mW m−2 with the Ha-B2 well reaching 65 mW m−2
lateral shear movement along the future Agulhas–Falklands (Goutorbe et al. 2008). This is a fairly low heat flow, suggesting
Transform. The WNW-trending late Jurassic–Early Cretaceous rift that present-day geothermal gradients will be in the region of 25 –
graben reach up to 4 km deep, and they are filled with lacustrine 30°C km−1 and the present-day oil window will only be reached at
clastics which are dominated by conglomerates and sandstone in the greater than 4 km burial depth.
onshore rifts (Fig. 10b). The rifts became submerged below sea level
in the late Valanginian towards the end of rifting with the deposition
of shallow-marine sandstones. The nearshore graben lack intra-rift
Reservoirs
faults (Paton 2006), but farther offshore graben have closely-spaced The onshore southern Cape Fold Belt comprises thick sequences of
normal faults with an approximate spacing of 3 – 4 km, creating pure quartzites that were folded and metamorphosed during the
many small structural traps in the synrift strata. There is an outer Permian age Cape Orogeny which developed a large mountain belt.
basement high along the Agulhas transform margin which may have Erosion of the Palaeozoic quartzites will have sourced high-quality
caused the basins to be restricted even during the early drift phase. reservoir sandstones during the basin development. The synrift
Berriasian–Valanginian sandstones have variable porosities, but
often exceed 25% (Beckering Vinckers 2007). Portlandian and
Source rock
Kimmeridgian sandstones tend to be more argillaceous, with
Kimmeridgian–Berriasian rift-phase source rocks have been identi- reduced reservoir quality of 9 – 25% porosity. Barremian–Lower
fied in the onshore Sundays River Trough, with 3 – 4% total organic Albian sandstones also have a good reservoir potential.
 The East African continental margin: a review

Hydrocarbon potential Cretaceous times. Only four wells have been drilled in the basin: one
well had minor traces of oil (Jc-D1) and one had gas shows (Jc-B1:
This basin has good potential for new plays, including stratigraphic Singh 2003).
traps, as well as many conventional rotated fault block plays. A
good example of the stratigraphic trap potential is the Ingwe
prospect which lies updip from the Hb-I1 well. Oil shows were Stratigraphy
encountered in the well in the interval correlated to bright reflectors, The synrift stratigraphy has been tested on the footwall highs in two
which gradually increase in amplitude updip away from the well of the wells, with thin sandstones and shales encountered. The
(Fig. 11). There are also stratigraphic traps in the Algoa Canyon shallow rift areas are mainly sand-prone, but better source rocks
with sidewall traps outside the canyon, which may be sealed by shales can be expected in the deeper half-graben that are undrilled.
shale-fill in the canyon. The drift sequence consists of deep-water clastics with basin-floor
fans and turbidite channel sandstones expected.

Durban Basin and Tugela Cone

Structure
Introduction
Rifting probably started in Early Cretaceous times associated with
This basin lies along the eastern termination of the Agulhas Fracture South Atlantic opening. The extension was initially slow so that the
Zone where the continental shelf widens suddenly (Fig. 12). The basal rift section covered the crest of the fault blocks. This was
Tugela River has produced a delta in this area which initiated in Late followed by rapid rifting with 3 km of wedge-shaped fill, which

Fig. 10 (a) Map of the Algoas and Gamtoos basins. (b) Seismic section and interpreted geological section; the location is shown in (a) (from Beckering
Vinckers 2007).
 I. Davison & I. Steel

Fig. 10 Continued.

thickens into the hanging-wall graben. Drape over the footwall high potential source rock (Beckering Vinckers & Davids 2008; Impact
blocks has created traps in post-rift Cretaceous sediments where Oil & Gas Ltd 2014).
bright amplitude anomalies have been detected (Battacharya &
Duval 2016).
Hydrocarbon potential

Source rocks and maturity Structural traps are present at the synrift level and in the Early to
Mid-Cretaceous strata, which are draped over the underfilled fault
The Jc-D1 well encountered oil shows in synrift sandstones which blocks. Stratigraphic pinch-out traps are also predicted (Beckering
are believed to have been derived from Upper Jurassic marine Vinckers & Davids 2008) (e.g. Fig. 12). This is a rank frontier basin,
source rocks (Beckering Vinckers & Davids 2008). Similar aged but has potential for oil-prone source rocks. There are no deep-water
source were encountered in DSDP 330, with 150 m of 3 – 5% TOC wells drilled to date.
Type II kerogen organic-rich shales of Kimmeridgian–Aptian age
on the conjugate Maurice Ewing Bank (DSDP 1989). Several
possible oil slicks have been observed in the offshore area, and gas South Mozambique Basin
chimneys and chemotropic mounds are observed on seismic data Introduction
(Van der Spuy 2009). An Aptian source rock may also be present.
The South Mozambique Basin is a large basin which has two
commercial onshore gas fields, Pande (3.4 Tcf in place) and Temane
Reservoir
(1.8 Tcf in place), and two undeveloped fields, Buzi with 2P
Synrift lacustrine sandstone reservoirs can be expected in the rotated reserves of 0.283 Tcf and the Njika Field (Fig. 13) (Boote &
fault block traps. Matchette-Downes 2009; www.energy-mp.com). Inhassoro has
Basin-floor fans of Mid-Cretaceous age have also been postulated recently been declared commercial by Sasol, although recovery will
(Dolphin and Camel leads) in the deep water that lies close to a be difficult as there is only a thin condensate/oil rim below the gas cap.
 The East African continental margin: a review

Fig. 11. Seismic section through the Ingwe Prospect, showing a high-amplitude event updip from the well, which is a possible reservoir sandstone. From
Simco (2010). Reproduced with kind permission of New Age Energy.

Stratigraphy have geochemical signatures indicative of marine shale, with high

gammacerane indicating a hypersaline source possibly from the
Volcanics and interbedded sandstones were encountered at the base Domo shales (Loegring & Milkov 2017).
of the Mazenga-1 and Domo-1 wells, which are thought to be lateral
equivalents to the Lebombo monocline volcanics dated at 182 Ma
(Klausen 2009). The Early Cretaceous marine clastics of the Reservoir
Maputo Formation are overlain by the Lower Domo Formation
Late Cretaceous nearshore marine sandstones (Grudja Formation) are
which contains dark grey marine shales that are probable source
the main reservoirs in the Pande, Buzi, Temane and Inhassoro fields
rocks. Palaeogene–Miocene (Cheringoma) shelf carbonates are
(Matthews et al. 2001). Domo Formation sandstones are also productive
present in the onshore area (Zacarias 2009).
in Nemo-1. Shallow-marine carbonates of the Cheringoma Formation
(Paleocene–Miocene age) may also be potential reservoirs.
Structure
The whole of the southern Mozambique plain may be floored by Hydrocarbon potential
Jurassic volcanics which lie on Karoo strata along the western edge, The drift section in the offshore area is relatively unstructured, and
but may be oceanic crust farther east. Early Cretaceous rifting phase this is probably why there are no deep-water wells for over 1000 km
produced the NNW-trending Xai Xai Graben, and other parallel rifts along the South Mozambique margin. The Inhassoro-9z well
onshore (Fig. 13). BP drilled the Xai Xai-1 well in the graben; but flowed a total of 200 000 barrels (bbl) of oil on an extended well
the well was dry, probably due to an immature or absent Albian age test, indicating significant potential for oil in this part of the basin
Lower Domo source. The other onshore graben are also believed to (Trueblood 2013). There is potential for further discoveries around
be shallow (1 – 3 km), so their hydrocarbon potential is poor. Slight the existing fields. However, the Early Cretaceous graben farther
folding occurred in the Late Cretaceous–Palaeogene strata offshore west (e.g. Palmeiras and Xai-Xai) are believed to be immature for oil
which has created the subtle Pande and Termane gas field structures generation (shallow burial) and no effective source rock has been
(Mabote 2008). Late Tertiary rifts at the southern termination of the proven so far. The offshore area of southern Mozambique has a
East African Rift System affect southern Mozambique, with the fairly thin Jurassic–Cretaceous sequence of approximately 3 s two-
Urema and Chissenga graben extending into the offshore, and way time (TWT) equivalent to c. 4 km, so source rocks may be in
several north–south-trending graben cutting though the coastal plain the oil window. Structural traps have been identified on seismic data
west of Pande and Termane fields (Fig. 13). with Early Cretaceous sediments draped over underlying rift fault
blocks (Salman & Abdula 1995).
Source rocks and maturity
Early Cretaceous Domo shales are the principal source rock that has Zambesi Delta and Angoche Basin
been identified. De Buyl & Flores (1986) indicated TOC levels of
Introduction
only 1%, but there is no detailed source information published. The
gas in the Termane, Pande, Inhassoro and Nijika fields is believed to The Zambesi River has a very large catchment area which has fed
be thermogenic, and derived from the Domo shales (Loegring & the offshore Zambesi Delta. North of the delta, the margin is known
Milkov 2017). Oil samples from the Termane and Inhassoro fields as the Angoche Basin (Fig. 14) (Mahanjane et al. 2014). The delta
 I. Davison & I. Steel

Fig. 12. Map of the Durban Basin.

has a maximum sedimentary thickness of c. 11 km, and it is indicate thick sedimentation with c. 3 km of Cretaceous strata and
bounded by the Beira High which lies at the seawards edge of the 3 km of Tertiary–Recent strata (Francis et al. 2017, fig. 3).
delta (Branquinho 2008; Mahanjane et al. 2014) (Fig. 15). Thick
sediment has spilled around the high and deposited to the east of the Structure
Beira High. Incipient oceanic crust may have formed along the
landwards side of the Beira High. Seismic refraction data suggest The Angoche Basin appears to be mainly floored by oceanic crust
thin dense crust NW of the Beira High, which is thought to be which has been imaged on seismic data, and seismic refraction data
oceanic SDRs, or highly thinned continental crust, with dense also support this (Leinweber et al. 2013; Mahanjane et al. 2014;
underplating of new igneous material (Mueller et al. 2016). Francis et al. 2017). The oceanic crust boundary is estimated to run
along the shelf break in c. 1000 m present-day water depth (Fig. 16).
Poorly developed SDRs are also present near the shelf break in the
Stratigraphy
Angoche Basin and east of the Beira High (Fig. 15) (Francis et al.
The Zambesi Delta consists of prograding marine clastics which 2017; Leinweber et al. 2013). The Angoche Basin is unstructured
were deposited in three periods of enhanced sedimentation during (Mahanjane et al. 2014; Francis et al. 2017), except for the
the following periods: Late Cretaceous (90 – 66 Ma), Oligocene transpressional segment along the Davie Fracture Zone which is
(34 – 23 Ma) and Late Miocene–Recent (10 – 0 Ma) (Walford et al. marked by large overthrusted Jurassic sequences (Mahanjane et al.
2005). The catchment area of the Zambesi is believed to have 2014).
doubled in size in the Pliocene. The Oligocene–Recent part of the The Zambesi Delta remained remarkably stable with little
delta reaches 4 km in thickness and covers an area of 200 000 km2. evidence of listric extensional faults or downslope toe compression.
The deep-water Angoche Basin has not been drilled but there are However, a minor detachment has been imaged at the Paleocene
seismic lines that have tied to the DSDP 242 borehole which level (Mabote 2008). Mild Tertiary age tectonic inversion has
 The East African continental margin: a review

Fig. 13. Map of the South Mozambique Basin.

occurred on the north side of the delta with Neogene strata observed containing Type II marine kerogen, with an average of 9.8% TOC
onlapping onto a broad anticlinal structure (Mabote 2008). The lack and HI of 300 – 600 (Thompson & Dow 1990). Heat flows of 60 –
of structuring perhaps explains why there are only five wells drilled 70 mW m−2 have been measured from the onshore Divinhe-1 and
in the onshore and shallow water, and no deep-water wells. Mambone-1 wells (Mahanjane et al. 2014).
The Beira High appears to be a cored by 25 km-thick continental
basement with rifted fault blocks clearly imaged on some seismic
Reservoir
lines (Fig. 15) (Salazar et al. 2013; Mueller et al. 2016). Structural
closures are present around the Beira High in rifted terrace blocks Deep-water turbidite sandstones can be expected throughout the Late
adjacent to potentially mature source rocks, and with large structural Cretaceous–Miocene section, and high amplitude-discontinuous
closures on the high. reflectors are imaged in the Cretaceous section that may be turbidite
channels and lobes (see fig. 3 of Francis et al. 2017). However, no
deep-water wells have been drilled to test the potential reservoirs.
Source rocks and maturity
There is no information available on source rock potential of the
Hydrocarbon potential
Zambesi Delta. However, an onshore oil seep has been recorded at
Angoche (Fig. 14). The ODP Leg 113 well 692B on the conjugate The Zambesi Delta has potential for many stratigraphic traps with
Antarctica margin penetrated 45 m of Valanginian source rocks channel sandstones. The large thickness of Tertiary sediment
 I. Davison & I. Steel

Fig. 14. Map of the Zambesi Delta and Angoche Basin.

would place any potential Mid-Cretaceous source rocks into the thick (5 – 6 km) around the sides of the high, so any potential Mid-
oil window. These source rocks have not been encountered to or Early Cretaceous sources may be in the oil window.
date, but no wells have been drilled seawards of the Mid-
Cretaceous shelf edge, where anoxic facies could be expected.
There is some suggestion of bright continuous reflections in the Rovuma Basin
mid-Cretaceous section which pinch out onto the Cretaceous
Introduction
shelf edge (e.g. De Buyl & Flores 1986, fig. 6 at 4 s TWT on the
eastern edge of the line). There is a lack of structure in the delta, The Rovuma Delta straddles the Tanzania–Mozambique border.
so stratigraphic traps will be the main targets. Most of the Recent giant gas discoveries have fuelled exploration along this
Angoche Basin also lacks any structure at shallower levels, and margin (Fig. 16). The Rovuma Basin continues 200 km south of
stratigraphic traps will be the main targets. However, it is very the delta as the Cabo Delgado and Lacerda sub-basins. The
highly structured along the Davie Fracture Zone, where Cachalote subcommercial gas discovery in 2013 highlights the
transpressional thrusts were developed during the Late Jurassic, potential of the margin to the south of the Rovuma Delta
and both clastic reservoir and source rocks may be developed (Fig. 16).
(Mahanjane 2014). At least 200 Tcf of gas in place has now been proven in the deep-
The Beira High has potential for very large structural closures in water area of the Rovuma Delta (Wentworth Resources Ltd 2015).
rotated fault blocks and drapes over the high. The sediments are Wells have also been drilled in the shallow water and onshore part of
 The East African continental margin: a review

Fig. 15. Seismic line through the Zambesi Delta and the Beira High. From INP Instituto Nacional de Petroleos Mozambique (2014).

the delta, where extensional listric faults and rollover anticlines are The main sliding occurred in the Oligo-Miocene, and minor
the main traps. These traps contain the Ziwani, Mnazi Bay and movement continued until the Mid-Pliocene.
Ntorya gas fields, but these are considerably smaller than the The Querimbas and Lacerda (or Nacala) graben are the offshore
offshore fields (Aminex plc 2015; Wentworth Resources Ltd 2015). continuation of the eastern branch of the East African Rift System,
and are seismically active (Mahanjane 2014; Franke et al. 2015;
Mulibo & Nyblade 2016). Rifting of the Querimbas occurred in the
Stratigraphy last 5 myr (Franke et al. 2015). However, older Jurassic age rotated
Karoo and Jurassic rifts are present around the Ibo High area and fault block traps are also present in the graben; and also further east
probably underlie the delta, they are presumed to source the of the Querimbas Graben, in the Comoros territory (Singleton et al.
thermally-generated dry methane gas. The onshore stratigraphy has 2014). It is not clear whether western Comoros is continental or
been tested down to the Aptian–Albian in the Mocimboa-1 well, rifted oceanic crust, but the graben are small and probably situated
which encountered marine marls at 3.3 km depth and had oil shows on extended oceanic crust (Fig. 17) (see also Phethean et al. 2016).
in Cretaceous sandstones. The Jurassic and Early Cretaceous The Querimbas Graben cuts across the distal part of the Rovuma
sections have not been drilled offshore; the deepest drilled strata are Delta, and sediment is diverted to flow north–south down the graben
Late Cretaceous clastics. The Rovuma Delta developed from Late axis (McDonough et al. 2016). Despite the rapid sedimentation rate
Cretaceous times and is still a site of major deposition from the expected at the delta front, the tectonic subsidence outpaces the
Rovuma River (Key et al. 2008). The Late Cretaceous Mifume sediment deposition and the seafloor is offset by over 1 km.
Formation consists of prograding clastics which are mainly
sandstones and conglomerates in the shallow proximal part of the
Reservoirs
basin, grading to distal mudstones and marls reaching up to 810 m
thick in the Mocimboa-1 well (Key et al. 2008) Turbidite sandstones channels and basin-floor fans are present over
most of the Rovuma Delta, with the youngest reservoirs of Late
Miocene age, and the oldest of Late Cretaceous age in the Ironclad
Structure well (Cove Energy plc 2011; Law 2011; Palermo et al. 2014;
The shallow shelf area of the Cabo Delgado Sub-basin contains Bendias et al. 2017). Net pay thicknesses vary from c. 30 to 200 m,
several prominent basement highs that make up the regional Ibo with high net:gross, excellent porosities and permeabilities. The
High trending north towards the Rovuma Delta (Fig. 16). Several high quality of the thick reservoir sandstones is attributed to flow
downthrown fault terraces have prospective structural traps which stripping of the turbidite flows due to strong northwards-directed
may require updip fault seal at Karoo, and Upper and Mid-Jurassic contourite currents which take out the fines to produce thicker mud
levels. Onlapping stratigraphic traps have potential at Lower levees on the northern side of the channels and a clean sand infill
Cretaceous levels surrounding the high. within the channels (Palermo et al. 2014).
The offshore Rovuma Delta is affected by three cells of updip
listric faults and downdip linked compressional toes (Palma,
Source rocks and maturity
Lunique or Mocimboa and Medjumbe: Law 2011; Mahanjane &
Franke 2014) (Fig. 16). The toe thrusts and anticlines first attracted The gas is >96% methane in Mnazi Bay (RPS Energy Canada Ltd
explorationists, but the largest gas fields are trapped below the 2013) and in the offshore giant fields. The source of the Rovuma dry
detachment surfaces, and in front of the delta in stratigraphic traps gas fields is believed to be either Jurassic or Triassic (Karoo) shales,
(Cove Energy plc 2011; Law 2011). There are also small gas but it is not clear whether this is an original gas-prone source or an
deposits in the toe thrust anticlines, but these are smaller than the overmature oil-prone source. Farther south, the Mecufi and Pemba
sub-detachment fields. The main detachment level is within the onshore oil seeps hint at oil-prone source rocks in the Jurassic and
Eocene shales, with a subsidiary Oligocene detachment above. possibly Karoo sediments. Therefore, the area west of the Ibo High
 I. Davison & I. Steel

Fig. 16. Map of the Rovuma Basin.

has a better potential for oil compared to the Rovuma Delta, where volcanics deposited on oceanic crust (see the following discussion
only gas is present. on the Mafia Basin).

Mafia and Mandawa basins

Hydrocarbon potential
Introduction
The best potential for future finds is in the downthrown terraces and
stratigraphic pinch-outs surrounding the Ibo High trend. Several The offshore Mafia Basin is bounded to the north by Mafia Island,
important oil seeps have been identified along the coastline west of the Rovuma Delta to the south and by the Davie Ridge Transform to
the Ibo High, indicating potential oil source presence (Fig. 16). the east. The onshore portion of the basin is known as the Mandawa
Although it should be noted that the Cachalote gas discovery is also Basin, which is separated from the offshore by the Pande Kizimbani
in this area. The presence of rifts at basement level east of the Davie High (Fig. 18).
Fracture Zone is potentially important (Fig. 18b), as this may imply The northern limit of the onshore Mandawa Basin is bounded by
that there are possible Jurassic source rocks present in this area, an east–west transfer fault, and to the south the basin probably
which are buried into the oil window, so that the exploration blocks extends and is buried underneath the Rovuma Delta. BG have
in the Comoros Islands may have some hydrocarbon potential discovered more than 15 Tcf of gas in the Mafia Basin and estimate
(Fig. 18) (Craven 2015; Roach et al. 2017). However, these are a recovery factor of 60 – 80%, and Exxon-Mobil have an estimated
generally fairly small with 2 km of reflective strata that may be 22 Tcf of gas in place in Block 2 (Offshore Energy 2013; 2b1st
 The East African continental margin: a review
Fig. 17. Line drawing through the Rovuma Delta and Querimbas Graben, offshore Tanzania and Comoros. The line location is shown in Figure 16.
 I. Davison & I. Steel

Fig. 18. Map of the Mafia and Mandawa basins.

Consulting 2015). Most of the gas is dry, but Mzia-1 contained Stratigraphy
condensate in Block -1, where oil may have been generated first but
was then forced out of the reservoir by later gas generation. The synrift stratigraphy is well documented in the Mandawa
This area is conjugate to the Morondava Basin of Madagascar onshore basin (Quinton & Copestake 2006). Pliensbachian strata
where high-quality source rocks have been encountered in the consist of basal sandstones overlain by Mbuo clastics and the
Permian Sakamena Shales, which source the Bemolanga tar sands. Nondwa halite of Toarcian age. The overlying sequence is mainly
Twenty wells (only seven with total depths (TDs) >1000 m) have shallow-marine limestones and clastics of Upper–Middle Jurassic
been drilled in the onshore Mandawa Basin, but with no discoveries, age. The Cretaceous sequence comprises fine-grained clastics and
although three wells (Mita-Gamma-1, Mandawa-7 and Mbate-1) occasional limestones. Offshore, the Mafia Basin contains greater
had oil shows (Quinton & Copestake 2006). than 7 km of Cretaceous–Recent clastic sediment fill, which is up to
The main structural feature in the offshore area is the sinistral 5 km thick east of the Davie Ridge. In the offshore Mafia, the wells
transcurrent Sea Gap Fault, which now has a north–south-trending have only penetrated down to the Late Cretaceous, which is a deep-
string of >10 gas fields discovered in structural traps along the water clastic sequence.
fault (Higgins & Sofield 2011; Ophir Energy 2016) (Fig. 18). Two
major gas fields have been discovered in Paleocene fans in the Structure
northern part of the margin, which have >10 Tcf of gas in place, and
are not associated with the Sea Gap Fault (Chewa and Pweza: The onshore Mandawa Basin rifting initiated in the Pliensbachian
Fig. 18). and probably continued into the Late Jurassic. The main rift faults
 The East African continental margin: a review

Fig. 19. Seismic section through the onshore Mandawa Basin. The Mihambia prospect has now been drilled and was a dry hole. Modified from Quinton &
Copestake (2006). The line location is shown in Figure 18.

are orientated north–south, but there are important ENE–WSW- sourced all the large gas discoveries. The Palaeogene also contains a
trending transfer faults present in the basin and one of these marks waxy plant material source rock, but is thought to be immature over
the northern limit of the basin. most of the basin. It is not known whether these source rocks also
Toarcian salt produced decoupling of the basement involved rift have oil potential or whether they are only gas-prone.
faults, and large post-salt listric faults sole out on the salt horizon
(Hudson 2011) (Fig. 19). Salt diapirism occurred through the
Reservoir
Jurassic into the Cretaceous. The offshore Mafia Basin may also
contain thin salt, but this has not been identified on the seismic data The onshore Songo Songo gas field has Neocomian Kapimatu and
so far. There is a small thickness of Cretaceous and Tertiary transgressive marine Albian sandstones. The offshore gas fields are
sediment onshore; and the basin was uplifted and eroded some time in deep-water turbidite sandstones ranging from Albian to Eocene
prior to, or during, the Tertiary. age (McDonough et al. 2016; Ophir Energy 2016). The Chewa well
In the offshore region, deep rotated Jurassic age? faults blocks can proved channelized sandstone reservoirs throughout the Paleocene–
be imaged even east of the Davie Ridge, which is supposed to be a Miocene section, with porosities up to 30% and permeabilities >1 D
transform boundary separating oceanic and continental crust (Fig. 17). (Sansom 2013).
However, recent seismic data suggest this may be an ocean–ocean
transform and the OCB lies farther west (Phethean et al. 2016). Other
Hydrocarbon potential
authors have suggested continental crust may extend east of the Davie
Ridge (Craven 2015; Roach et al. 2017), and this may not be a simple Potential stratigraphic traps have been mapped throughout the Mafia
single transform boundary but an amalgamation of subsidiary Basin on 3D seismic data and many more gas fields will probably be
transforms (Phethean et al. 2016). The small size of the rifts and discovered (Fig. 18) (Ophir Energy 2016).
the high amplitude of the reflective fill east of the Davie Transform Most of the structural traps along the Sea Gap Fault have been
seems more indicative of faulted oceanic crust with a volcanic drilled at shallow depths, but deeper reservoirs may have some
half-graben fill rather than Karoo age sediment in our opinion. potential. In the onshore Mandawa Basin, the key issue is that the
The Seagap Fault is a long-lived Jurassic–Recent fault with late best mature source rock is separated from the reservoirs by the
sinistral strike-slip displacement (Higgins & Sofield 2011). It has intervening Toarcian salt.
created prominent positive flower structures, which trap a string of
gas fields draped along the fault (Fig. 18).
Zanzibar Coastal Basin, and the Zanzibar, Pemba and
Tembo troughs
Source rocks and maturity
Introduction
Source rocks are potentially present in the Karoo sequence in the
onshore Mandawa Basin, as oil shows were encountered in the pre-salt The Zanzibar, Pemba and Tembo troughs are located between the
section in two wells. The Upper Nondwa Toarcian age salt contains African mainland and the Pemba and Zanzibar islands (Fig. 20).
thin interbedded shales with 3 – 9% TOC and HI values of 300 – 1000 The Sunbird-1 well discovered a small column of oil in a Miocene
with Type II/III kerogen (Kagya 1996; Quinton & Copestake 2006). carbonate reef perched on the eastern margin of a Tertiary graben
However, the western part of the onshore basin contains less than 3 km (Brown 2013; Pancontinental Oil & Gas 2014). The deeper
of sedimentary section above the source rock interval and therefore offshore area to the east is named here as the Zanzibar Coastal
the source may be immature. Nonetheless, the basin thickens towards Basin, which is believed to have a similar geology to the Mafia
the coastline and source rocks may be mature in this onshore area. Basin immediately to the south. Several onshore wells have been
In the offshore Mafia Basin, the main source rock is believed to drilled on the mainland and the islands, but these were dry.
be either Karoo shale or synrift Jurassic age shales, which have However, there are important oil seeps on Pemba Island (Maende
 I. Davison & I. Steel

Fig. 20. Map of the Zanzibar, Pemba and Tembo troughs, and the Zanzibar Coastal Basin.

Fig. 21. Cross-section through the Pemba Trough. From Parsons et al. (2013). The line location is shown in Figure 20.
 The East African continental margin: a review

Fig. 22. Map of the Lamu and Somalia basins.

& Mpanju 2003). There is only one deep-water well in this area, Structure
Mkuki-1, which encountered reservoir sandstones, but was dry
(Fig. 20). The onshore Selous-Ruvu Karoo-aged trough trends NNE and
intersects the margin around Pemba Island. This probably
controlled the Jurassic age rifting trend to be of a similar orientation.
Stratigraphy The localized Neogene Zanzibar, Pemba and Tembo troughs
broadly trend north–south and form a right-stepping en echelon
The stratigraphy of the offshore is only known down to the Late pattern. The troughs may be associated with transtensional strike-
Cretaceous from the Pemba-5 well. The shallow basin is expected to slip movement along north–south-trending faults, and faulting is
contain deep-water clastics in the Cretaceous interval, shallowing to still active with offsets at the seabed. The two islands of Pemba and
deltaic sandstones and shales in the Palaeogene (Nelson 2006). The Zanzibar are basement-cored highs. The Pemba High is covered by
deep-water rocks are expected to be clastics, similar to the Mafia thick Palaeogene deltaic strata, suggesting that this is a Neogene
Basin strata. The basin fill in the Zanzibar, Pemba and Tembo feature caused by inversion.
troughs are Tertiary clastics and carbonates which may reach up to
8 km in thickness (Fig. 21) (Parsons & Nilsen 2012; Parsons et al.
Source rocks and maturity
2013). The Zanzibar-1 well was drilled on the western edge of the
Zanzibar Trough and encountered Paleocene sandstones and shales, Prominent oil seeps are present on the Pemba and Nyuni islands
overlain by Eocene marine clastics and limestones, followed by (Matchette-Downes 2003) and on the mainland in the west of the
Neogene clastics. Pemba Trough (Afren 2014). Farther south, the Wingagonyo tar
 I. Davison & I. Steel

sand is believed to be a palaeo-oil column? of 45 m in Neocomian– which time a thick carbonate platform had developed in the Lamu
Aptian sandstone of the Kapatimu Formation. The Pemba Trough is Basin.
expected to contain Eocene age source rocks such as those The shallow shelf strata contain Karoo-aged rift strata, overlain by
encountered on Pemba Island in the Pemba-5 well. One sample Jurassic limestones and shales which crop out in the Mombassa
from this well had a 7% TOC and a HI of 668 (Nelson 2006). region. The north–south-trending Maridadi Trough is filled by Early
Although the thickness and distribution of this Eocene source rock and Late Cretaceous and Tertiary clastics that exhibit growth
are not fully known, it probably sourced the small amount of oil thickening into the main boundary fault, indicating a multi-stage
discovered in a Miocene carbonate reef in the Sunbird-1 well, which rifting event (Fig. 6). Carbonates and sandstones of Mid–Late
lies in the north of the Pemba Trough (Brown 2013; Pancontinental Cretaceous age are present on the shelf and thin out at the Simba-1
Oil & Gas 2014). However, the significance of this oil is still not well. These are separated from the Tertiary clastics by an important
clear, as few details have been released to date. The post-Eocene unconformity. Another unconformity separates the Oligocene clastics
sediment reaches up to 6 – 7 km thick in the centre of the trough, so from the Miocene limestones. The deeper stratigraphy of the offshore
there is a risk of gas (Parsons & Nilsen 2012; Parsons et al. 2013). Lamu Basin is not known, and the published wells has only drilled
Eocene source rock should be in the oil window on the margins of down to Late Cretaceous levels (Pomboo-1 and Simba-1 wells).
the trough. Some fair source rocks of Middle Jurassic age were also
encountered in the Makarawe-1 well with a TOC of around 1 – 2% Structure
(Nelson 2006). Present-day depths in the Pemba Trough indicate
that these source rocks could be generating hydrocarbons. The deep underlying rift sequence is not clearly imaged, but Karoo
Elsewhere, the source rocks in the Zanzibar Coastal Basin are and Jurassic age rifts can be expected. The large NW-trending Walu
expected to be of Jurassic age, but which are probably generating High is buried, although clearly identified on the gravity data, and
gas due to general deep burial below the Lamu Delta. this forms the eastern boundary of the Maridadi Trough, which is
believed to be Early Cretaceous age (Fig. 6). The Walu downslope
gravity sliding has occurred along the northern portion of the Lamu
Reservoir Embayment (north of the Walu High) and in southern Somalia
Good reservoir sandstones were encountered in the Pemba-5 well in (Juba Sub-basin) to produce a thin-skinned gravity fold belt, where
the Eocene and Oligocene with intraformational shale seals the Pomboo-1 well is located. The detachment surface is probably a
expected in the Zanzibar, Pemba and Tembo troughs (Kejato Palaeogene shale horizon (Kearns et al. 2016) (Fig. 23).
2003). The porosity of these sandstones ranges from 22 to 28%
(Nelson 2006). Potential reservoirs in the deep Zanzibar Coastal Source rocks
Basin are not known as there are no public domain wells. However,
deep-water turbidite sandstone reservoirs can be expected. An overmature Jurassic or Permian source is suspected for the
Mbawa-1 gas discovery located in an Early Tertiary structural closure
over the Walu High. Permian bitumen has been recovered from the
Hydrocarbon potential Ria Kalui-1 well (located in Fig. 20). The presence of the Palaeogene
detachment below the deep-water gravity fold belt suggests that the
There is significant potential for oil discoveries in the Pemba,
detachment weakness could be caused by overpressure.
Tembo and Zanzibar troughs if a Tertiary source rock were present.
The Pemba-5 and Mafia-1 wells had oil shows. The Zanzibar,
Pemba, Tembo troughs have the best chance of oil, whereas the Reservoirs
deep-water coastal Zanzibar Basin is considered to be more gas-
Cretaceous and Tertiary reservoir sandstones are present in the
prone. Deeper targets on the Zanzibar and Pemba highs can also be
offshore area, which have been sourced from rivers flowing down
considered to have some oil potential. The deep-water basin is
the Anza Graben to the coastline. The Mbawa-1 deep-water well
believed to be mainly unstructured at Cretaceous and Tertiary levels,
encountered 52 m of net pay in Upper Cretaceous sandstone
and stratigraphic trapping will be required.
reservoirs (Pancontinental Oil & Gas 2014). Good Tertiary turbidite
sandstone reservoirs can be expected in the Lamu Embayment.
Lamu and southern Somalia (Juba) Basin
Introduction Hydrocarbon potential
The Lamu Basin has good reservoir potential with a large amount of
The Lamu Basin straddles the onshore and offshore, and is located at
clastic sediment deposited onto a delta-fed from the Anza Graben.
the SE extension of the onshore Anza Graben, which initiated in the
There is a high risk of gas in the mid and outer shelf, due to the thick
Upper Jurassic?–earliest Cretaceous (Fig. 22). Nine deep-water
Tertiary fill. The deep-water gravity fold belt contains large
wells have been drilled in the basin. Simba-1 (west gas shows) and
anticlines which probably host Late Tertiary turbidite sandstone
Pomboo-1 (dry) were both drilled on anticline traps. The reason for
plays, but hydrocarbons will need to migrate from a deep source
failure is not known. The Mbawa-1 well was drilled in 2012, which
through the overpressured detachment.
discovered an uncommercial gas field in the southern Lamu;
Kubwa-1 was drilled in 2014 and encountered non-commercial oil
shows in reservoir-quality sands; and Kiboko-1, drilled in 2013, Somalia and Puntland Coastal Basin
encountered reservoir-quality sandstone.
Introduction
The onshore and shallow-water areas of Somalia were explored in
Stratigraphy
the 1950s–1970s and 31 wells (but only six offshore) were drilled.
The Lamu Basin was the site of a large amount of Cretaceous–Tertiary In 1960, the onshore well Coriole-1 tested 2 MMcfd (million cubic
delta deposition due to sediment flowing down the Anza Graben feet per day) of gas and recovered 100 bbl (barrels) of 36 – 47° API
(Nyagah 1995). There is good evidence that large rivers linked directly oil from Palaeogene reservoirs (Amsas Consulting Pty Ltd 2014;
between the ocean and the East African Rift, as 20 – 15 Ma whale Soma Oil & Gas 2014); and in 1965 the Afgoy-1 well tested 6.4 –
bones have been found in the Turkana Rift area (Mead 1975), by 9 MMcfd of gas from Upper Cretaceous–Paleocene reservoirs
 The East African continental margin: a review

(also onshore: Amsas Consulting Pty Ltd 2014) (Fig. 22). Both of Jurassic sequence is carbonate-dominated with minor shales,
these discoveries are located in the southern part of the margin near sandstones and gypsum (the Hammanlei and Uarandab formations:
Mogadishu. No wells have been drilled for the last 30 years because Piccoli et al. 1986; St John 2016). These carbonates are widespread
of civil war and political instability, and a Force Majeure was and extend over 1000 km inland, over the onshore Ogaden Basin
declared by all operators in 1989. Two of these blocks have been into Ethiopia and northwards across into Yemen (Al Thour 1997).
retained by Exxon and Shell, and in 2017 the country is planning to The shallow offshore area is also expected to have been a shallow-
offer new licence blocks (Hodgson 2016) water carbonate platform in Early–Mid-Jurassic times. The Jurassic
section is known to thicken seawards, so deeper water facies can be
expected in the deep offshore.
Stratigraphy
The deep offshore Upper Jurassic–Recent sequence is expected
The onshore geology is well known from 30 wells (Barnes 1976; to contain deep-water clastics, but this has not been drilled yet
Bosellini 1986, 1989, 1992; Piccoli et al. 1986). Karoo age strata are (Piccoli et al. 1986). Shallow-water carbonate deposition persisted
present along the margin and are believed to be part of a large through the Cretaceous and Tertiary in onshore northern Somalia,
intracratonic basin where the Triassic? Adigrat Formation basal with evaporitic sabkhas developed in the Hauterivian–Valanginian.
sandstone is correlated over very large areas onshore. The overlying Seismic data indicate that the Early Cretaceous–Recent deep-water

Fig. 23. (a) Cross-section through the Juba Basin, south Somalia. Interpreted from the seismic section in Kearns et al. (2016). Approximate location of the
line shown in Figure 23. (b) Cross-section through central Somalia showing a detached slab of Jurassic–Lower Cretaceous with toe compression dominated
by thrusting (modified from Soma Oil & Gas 2015). (c) Cross-section from northern Somalia showing rotated Jurassic fault blocks with a potential Late
Jurassic carbonate build-up on the footwall crest (Soma Oil & Gas 2015). Line locations are shown in Figure 22.
 I. Davison & I. Steel

Fig. 23. Continued.

offshore sequence consists of mainly mudstones with some approximately in the Mid-Cretaceous and limited to thrust
sandstone turbidites (Soma Oil & Gas 2015). The southern part of development (Fig. 23b) (Soma Oil & Gas 2015);
the margin is dominated by Late Cretaceous and Tertiary deltas, • in southern Somalia, a detachment also occurs at an Early
built across the margin with up to 4 – 5 km of clastic strata recorded Cretaceous level, with Late Cretaceous–Early Tertiary sliding
in onshore wells in southern Somalia (Piccoli et al. 1986). (Kearns et al. 2016), and with much larger folds and thrusts
affecting 3 km or more of strata (Soma Oil & Gas 2015);
• in Palaeogene shales, with sliding occurring in the Late
Structure Miocene–Recent causing folding of the seabed (Kearns
The margin has an abrupt transition from 25 km-thick continental et al. 2016) (Fig. 23a).
crust to hyper-extended 5 – 10 km-thick crust, which is located at Detachment shales were probably overpressured and generating
the present-day continental slope (Kearns et al. 2017). Outboard, hydrocarbons at the time of sliding (Stanca et al. 2016; Kearns et al.
the thinned crust may extend to 100 – 150 km past the shelf edge in 2016) (Fig. 23). Bright reflectors are imaged in the Early–Mid-
the Obbia Basin, and exhumed mantle has been suggested Cretaceous levels in the deep water, which may be source rock
(Ringenbach et al. 2017). The margin widens in Puntland to the intervals (see the seismic line in Kearns et al. 2016).
north, with continental crust extending out to Socotra Island
(Richardson et al. 1995) (Fig. 23). This is a transtensional margin
Source rocks and maturity
during Late Triassic–Early Jurassic rifting, and a transform margin
during north–south ocean spreading in the Mid-Jurassic. Several No source rocks have been proven in the offshore basin so far.
strike-slip structures have been identified on the seismic lines with However, good source rocks are present in the Upper Jurassic
unusual bed dip changes and inversion features (Fig. 23). It has been Uarandab Formation in the Ogaden Basin with 2 – 6% TOC, which
suggested that the Cretaceous Nogal Rift may extend eastwards into has probably sourced the moveable oil discovered in the Calub-1
the northern offshore area, but there is no indicative gravity anomaly. and 3 wells (Ali 2006, Boote & Matchette-Downes 2009).
The deep crustal structure consists of rotated fault blocks with Karoo
and Early Jurassic growth strata similar to the rest of the margin (fig. 4 Reservoir
in Soma Oil & Gas 2015; Kearns et al. 2016, 2017; Stanca et al.
2016) (Fig. 23). Mid-Jurassic–Early Cretaceous strata are draped over Late Cretaceous–Tertiary reservoirs are most likely to be along the
the fault blocks, and Jurassic carbonate build-ups are probably southern and central portion of the margin in the Lamu Embayment
present on fault block crests (Fig. 23c) (Soma Oil & Gas 2015). and the Juba and Coriole sub-basins, where a thick Cenozoic section
An important phase of inversion has affected the central part of of 4 km has been proven by onshore wells, and discoveries have
Somalia, which probably initiated in the Late Cretaceous (Fig. 23b), been made at Coriole-1 and Afgoi-1 (Fig. 22) (Piccoli et al. 1986).
but continues into the Late Miocene father north (Fig. 23c). The
transform margin produced a steep continental slope which has Hydrocarbon potential
favoured the development of important gravity fold belts. The
The Somalia margin is very narrow but large fold structures are
detachment levels occur at various levels and with different sliding
present in the Juba Sub-basin (Kearns et al. 2016; Stanca et al.
times:
2016; Soma Oil & Gas 2015) (Fig. 23). The shelfal collapse of the
• in probable Early Cretaceous shales in central Somalia in the Late Cretaceous–Tertiary deltas in the southern area will have fed
vicinity of the Meregh-1 well, with sliding occurring turbidite sandstone reservoirs out into the deep offshore; and
 The East African continental margin: a review

stratigraphic and anticlinal traps can be expected, either formed by rocks would be predicted to be better quality. Karoo source rocks
tectonic inversion involving the basement (e.g. the large fold on the were encountered only in well Reith Bank-1 with mudstones
eastern end of Fig. 23b) or by toe compression at the head of major containing 2.4 – 6.7% TOC which was gas-prone. Seagull Shoals-1
detachment surfaces (Fig. 23a and b). Further north, in the Obbia and Reith Bank-1 penetrated Jurassic mudstones with up to 5.8%
Sub-basin, the sediment is less thick, with 3 s TWT of strata present TOC, and coals up to 65.2% TOC (Matchette-Downes 2006a,
that should place any potential Jurassic or Karoo age source rock 2010). However, these are fairly thin source horizons.
into the oil window (Stanca et al. 2016). A late Jurassic carbonate Late Jurassic–Early Cretaceous marine shales have TOCs of up
platform has been mapped in this area (Soma Oil & Gas 2015); and to 2.1% in the Owen Bank A-1 well (Petroseychelles 2013). Oil
Cretaceous strata are draped over the underlying large Jurassic fault shows have been analysed from Early Jurassic Karoo sandstone
blocks, and large closures are predicted in the Obbia Sub-Basin and facies, with two oil families recognized of Liassic–Triassic
further north (Fig. 23c). and Upper Cretaceous–Palaeogene affinity (Matchette-Downes
2006a, 2006b, 2010).
Seychelles
Reservoir
Introduction
Potential reservoirs are present in Karoo sandstones with porosities
The Seychelles–Mascarene–Ritchie and Saya de Malha banks form up to 23% (Reith Bank-1 well produced up to 1200 bbls of water/
a continental ribbon of Pan-African age (800 – 750 Ma: Tucker day: Petroseychelles 2013). Cretaceous sandstones and Tertiary
et al. 2001) surrounded by oceanic crust, which separated from limestones are also potential reservoirs, with porosities of up to 18%
Africa around 175 – 165 Ma and then from India around 70 – 65 Ma recorded in the carbonates (Petroseychelles 2013).
(Fig. 8) (Eagles & Hoang 2014; Reeves 2014; Davis et al. 2016;
Reeves et al. 2016). The ribbon of continental crust extends SW
from Mahe Island for approximately 1000 km towards the Nazarene Hydrocarbon potential
Bank (Davison et al. 2015) (Fig. 8; see also the Supplementary The hydrocarbon potential of the Seychelles is difficult to assess
material). Confidential seismic data indicate rifts with up to 6 km of with the limited well information available (four wells). Although
sediment thickness on the Mascarene Bank at a latitude of 7° S good levels of TOC have been found in Karoo source rocks, the
(author’s own observations). Four offshore wells have been drilled organic material is gas-prone. Many large rotated fault blocks are
in shallow-water Seychelles, but only one of these has tested a viable present throughout the Seychelles Mahe Bank, but an even larger
structural trap and reached the intended objective horizon number of blocks is predicted in the continental ribbon that extends
(PetroSeychelles 2013). Three wells (Owen-Bank-1, Seagull 700 – 1000 km south of the Seychelles Islands towards Mauritius,
Shoals-1 and Reith Bank-1) had oil shows at various depths. and this area is totally unexplored. This is one of the largest
There is a comprehensive 2D seismic coverage of most of the unexplored stranded continental fragments in the world, and has
prospective area, and seismic data have been recently acquired some good hydrocarbon potential in the Karoo and Jurassic half-
across the extension of the continental ribbon far to the SE. graben, although reservoir quality may not be so good, and this is a
very remote offshore location.
Stratigraphy
The wells have encountered a Triassic continental Karoo section Majunga and Ambilobe (or Diego) basins, Madagascar
containing thin coals with limited source rock potential, but did not Introduction
reach the Lower Triassic–Permian section. The Jurassic section
consists of Early Jurassic delta clastics followed by Middle Jurassic These are attractive basins that contain both Karoo and Early Mid-
nearshore carbonates and Upper Jurassic–Early Cretaceous fine- Jurassic rift fill. Thick Toarcian age salt was deposited in the
grained clastics (PetroSeychelles 2013). The Late Cretaceous– offshore, but there are no indications of evaporites in the shelfal
Paleocene section is also fine-grained marine clastics, including wells or onshore (Figs 24 and 25). The shallow part of the basin has
some volcanics, which was followed by carbonate bank deposition been explored, with 11 wells in the onshore that have encountered
on the plateau in the Tertiary, with deep-marine clastics further gas and oil shows (Mahajamba-1 and Mariarano-1). Oil shows have
offshore. Basalts equivalent to the Deccan traps of India are present been reported in shallow boreholes onshore drilled in the Ambilobe
in the Seychelles, which were erupted at c. 65 Ma (Collier et al. Basin (PuraVida Energy 2015). Belobaka-1 was the last well drilled
2008; Ganerød et al. 2011; Owen-Smith et al. 2013). in the Majunga Basin, which was by Hunt Oil in 2000 (Webster &
Ensign 2007).
Structure
Stratigraphy
Rifting occurred in the Karoo and Jurassic times producing half-
graben with up to 2 – 3 km of sedimentary fill around the Mahe Karoo age Sakamaena Formation strata consist of black shales and
Island area. A second phase of transtensional rifting occurred along thin sandstones containing Late Permian reptile remains
the southern edge of the Seychelles Plateau in the Cretaceous from (Razafindrazaka et al. 1999). Seismic data indicate that the
100 Ma, with up to 6 km of sediment deposited in 10 – 15 myr Sakamena section is also present in the centre of the onshore
(Morrison 2011; Robinson et al. 2012). Transpressional wrench basin. The Sakemana Formation is unconformably overlain by
faulting created positive flower structures, which are potential Isalo sandstones. Jurassic rifting was short lived, and commenced
hydrocarbon traps. An important phase of volcanism occurred in the in the Sinemurian and ended in the Bajocian in the Majunga
Late Cretaceous (84 – 78 Ma), along with the equally important (Besairie 1972; Papini & Benvenuti 2008). The rift fill contains
Deccan age (65 Ma) volcanism. red clastics, overlain by organic-rich marls and limestones of the
Beronono Formation, and salt of Toarcian age (Besairie 1972). In
the shallow water, the marine incursion was accompanied by
Source rocks and maturity
deposition of shallow carbonates (Besairie 1972; Papini &
The wells have not penetrated any significant oil-prone source Benvenuti 2008). These are overlain by Bajocian–Upper Jurassic
rocks, but have never tested the deep half-graben areas where source shallow-marine clastics and limestones. The Early Cretaceous
 I. Davison & I. Steel

Fig. 24. Geological map of Madagascar. The location of the Majunga section in Figure 25 shown in red and the approximate location of the Morondava
section in Figure 26 is in black.

sequence is dominated by marls with several lignite beds Cretaceous, and these have produced large potential sub-salt traps
preserved, and is overlain by Cenomanian–Late Cretaceous for earlier reservoirs (Tari et al. 2004) (Fig. 25). Deep-water toe-
clastics. Marine Tertiary sediments consist of dolomites, sand- thrusts and folds are present near the seawards edge of the salt
stones and marls in the shallow section (Razafindrazaka et al. basin.
1999), and deep-water shales and turbiditic sandstones can be
expected in deep water. Source rocks and maturity
The Beronono organic-rich shale was deposited in the Majunga
Structure
onshore area in Toarcian–Bajocian times (Besairie 1972). These
The onshore Karoo age rift faults trend NE–SW parallel to the source rocks contain TOC levels up to 10% with Type I/II organic
onshore trend of the Majunga Basin (Webster & Ensign 2007). In material (Tari et al. 2004; Webster & Ensign 2007). There is no
the offshore, the deep Jurassic fault blocks are poorly imaged and information on possible Cretaceous source rocks, which would
the rifts are not well defined, but it is expected to be similar (NE– significantly upgrade the deep-water area if these were present, as
SW). The Toarcian age salt became mobile soon after deposition, the Jurassic source rocks may be in the gas window in the main salt
and resulted in tall diapirs and allochthonous salt sheets in both the basin. However, below the allochthonous salt sheets, the source
Ambilobe and Majunga basins (Tari et al. 2004) (Fig. 25). The rocks will be cooled due to the high conductivity of the salt and
allochthonous salt sheets probably extruded during the Early could have remained in the oil window (Davison & Cunha 2017).
 The East African continental margin: a review

Fig. 25. Geological section across the Majunga Basin, based on seismic data courtesy of ION Geophysical. The line location is shown in Figure 24.

Reservoirs deep-water potential is difficult to assess. There have been no

offshore wells drilled in the last 40 years, making this a potentially
Karoo age reservoir sandstones can be expected, with Triassic age attractive overlooked basin.
Isalo sandstones.
Middle Jurassic carbonates are potential reservoirs along the shelf
edge, and oolitic limestones have porosities of 12 – 22% in the
Morondava Basin, Madagascar
Belobaka-1 well (Webster & Ensign 2007). The offshore area is Introduction
expected to have Cretaceous and Tertiary deep-water turbidite
sandstone reservoirs. Uplift probably occurred on Madagascar The Morondava Basin has been explored since the 1960s, and hosts
during the Jurassic rifting and during Late Cretaceous magmatism, the large tar sand accumulations of Bemolanga and Tsimiroro (16.5
producing erosion and consequent deposition of deep-water turbidite and 3.5 billion bbls in place, respectively: Fig. 24). The oil–water
facies. There is no information on the reservoir sandstone quality. contact is preserved in the shallow Tsimimoro wells, indicating that
these were live oil fields; the exposed reservoir has subsequently
been biodegraded to tar to form a seal to the heavy oil below (Robert
Hydrocarbon potential
Webster pers. comm. 2012). The 14.8° API oil in Tsimiroro is now
The Majunga Basin is a very attractive basin with good potential for being used for local power generation (Madagascar Oil 2015).
oil in the shallow shelf area, which is derived from good-quality oil- Approximately 58 exploration wells have been drilled throughout
prone Jurassic source rocks. The deeper-water area is probably gas- the Morondava Basin, with three small sub-commercial gas
prone as the Jurassic source rocks are too deeply buried, except discoveries (Sikily-1 tested 2.65 MMscf/d (million standard cubic
where the allochthonous salt sheets are present, allowing the source feet per day): Fig. 24). Seismic data are poor, and wells have not
rocks to stay in the oil window. Stratigraphic pinch-out traps are always drilled on structure or deep enough to test the better Karoo
possible in Cretaceous sandstones in the shallow shelf and onshore. reservoirs onshore. There have been no offshore wells drilled since
There are no wells drilled in deeper than 500 m water depth, and the the 1980s.
 I. Davison & I. Steel

Stratigraphy Source rocks and maturity

The oldest Karoo age sedimentary rocks are found in the Morondava An Early Triassic marine incursion occurred in Madagascar, and the
Basin, where glacial and lacustrine deposits of the Late Carboniferous– middle Sakamena Formation contains dark grey shales and
Late Permian age Sakoa Group reach up to 2 km in thickness (Wescott bituminous limestones which are believed to be the source of the
& Diggens 1997). The overlying Permian Sakamena Formation and Bemolanga and Tsimimoro tar sands. The Beronono Formation of
Late Triassic Isalo Formation consist mainly of continental fluvio- Early–Mid-Jurassic age has been encountered with the TOC
lacustrine strata (Besairie 1972; Wescott & Diggens 1998). The Karoo reaching 12% in the Majunga Basin. Jurassic Bemaraha deep-
sequence may reach up to 11 km in thickness in the southern water carbonates may also be a potential source rock. Sakamena
Morondava, and the deeper parts of the Karoo stratigraphy have not Formation source rocks contain 5 – 6% TOC (Webster & Ensign
been tested in this area (Boast & Nairn 1982). The Sakoa sequence 2007). Triassic age Isalo shales are also present with Type III gas-
consists of tillites, sandstones, shales, limestones and coals of Late prone material with 17 – 22% TOC. The Karoo and Jurassic sources
Carboniferous–Early Permian age. The top of the Sakoa Formation is are predicted to be present in the offshore. The Cretaceous section
marked by a shallow-marine limestone of Early Permian age (Wescott may also have potential source rocks which have been analysed in
& Diggens 1997). The overlying Sakamena Formation is comprised of the Saronala-1 well, and these rocks may be buried deep enough to
a lower sandstone, middle shale and upper sandstone units reaching up generate oil (Tari 2016).
to 4 km in thickness (Wescott & Diggens 1998).
There is believed to have been an important marine incursion in Reservoir
the Early Triassic, and the middle Sakamena Formation contains
dark grey shales and bituminous limestones that extend over most of Good-quality Early and Late Cretaceous sandstones reservoirs can
the basin and range from 200 to 650 m in thickness (Geiger et al. be expected, which were derived from the uplift of Madagascar
2004). These are the source of the Bemolanga and Tsimimoro tar during this time, and sedimentary onlaps of this age are present
sands, onshore Madagascar (Webster & Ensign 2007; Ouedraogo along most of the margin. Large channel structures are visible on
2012). The Isalo Formation is Triassic–earliest Jurassic? age and seismic data (Matchette-Downes 2006a). The Karoo age reservoir
consists of mainly sandstones which reach up to 5 km in thickness. sandstones are relatively poor quality and these are not considered to
The top of the Isalo Formation is marked by an unconformity and is be viable reservoirs in the deep offshore, except where they are less
overlain by the Early Toarcian strata. deeply buried on the Juan de Nova Ridge.
The Toarcian–Aalenian age Andafia Formation reaches up to
1500 m thick in the subsurface (Dina 1996; Boast & Nairn 1982); it Hydrocarbon potential
contains shallow-water carbonates, sandstones and shales, with
deeper-water shales present in the deeper half-graben. The strata There is limited potential for structural traps in the offshore basin,
show wedging on seismic data, indicating that they were deposited except along the Davie–Juan de Nova Ridge where structural
during rifting (Geiger et al. 2004). These are unconformably inversion has occurred in the Late Jurassic, and the Karoo and
overlain by shallow-marine carbonates of the Bemaraha Formation Jurassic section have been uplifted by several kilometres. The Davie
of Bajocian–Bathonian age, which can reach up to 600 m thick Ridge inversion has also produced large north–south-trending
(Ambatolahy-1 well, located in Fig. 24) (Geiger et al. 2004). The anticlinal fold closures (Fig. 26). Cretaceous pinch-out traps are
Callovian sequence consists of marginal-marine and fluvial present along the eastern and western margins of Morondava Basin,
siliclastics in the northern and central part of the basin (Mette where turbidite deposits may have been trapped (Fig. 26). The
2004). The Oxfordian–Kimmeridgian succession consists of onshore basin has good potential for Karoo and Early Jurassic
condensed shallow-marine to open-marine siliclastics with ferru- structural traps, with faults juxtaposing the Beronono shales against
ginous oolitic beds. The overlying Early Cretaceous sequence Isalo Formation sandstone reservoirs. Most of the onshore wells
initiates with an Aptian age conglomerate overlain by marine shales have been drilled on very poor seismic data, so the lack of success
and sandstones (Mette 2004). The Tertiary sequence is dominated does not necessarily signify that the basin has poor potential.
by limestones and dolomites and marls of Paleocene–Miocene age, Improved seismic imaging will open up some significant low-cost
and is overlain by Pliocene clastics and limestones (Stone & Leroy exploration opportunities onshore.
2003). Major lava extrusion and sill injection took place in the Late Excellent oil-prone source rocks are proven in the Karoo and the
Cretaceous (c. 88 Ma), which partially masks the deeper geology on later Jurassic rift sequence onshore, and both of these sources
seismic sections (Storey et al. 1995) (Fig. 26). should be in the oil window over most of the onshore and offshore
portions of the basin. Gas chimneys have been recognized above
several synrift faults (Matchette-Downes 2006a; Tamannai 2008).
Structure Reservoir quality in Karoo and Jurassic-aged strata is poor, so this
play would only be commercial onshore. Better quality Cretaceous
The initial Karoo rifting is believed to have occurred in a sinistral and Tertiary turbidite sandstones will be present offshore, and the
transtensional regime with pull-apart basins locally developed; main traps are predicted to be stratigraphic pinch-outs along the
followed by NW-trending extension to produce NE-trending fault shelf margins (Fig. 26).
blocks (Schandelmeier et al. 2004). The Jurassic rifting continued
probably until the Toarcian, with north–south-trending rift faults
Conclusions
active. The basin margin was uplifted and eroded in post-Jurassic
times, probably during the Late Cretaceous magmatic event, The central East African continental margin has become a focus of
causing a prominent basinwards tilt. intense exploration activity in the last few years since the discovery
The Davie–Juan de Nova Ridge is located along the north–south of more than 200 Tcf of thermally-generated gas in Mozambique,
transform margin which bounds the Morondava Basin to the west Tanzania and Kenya. Most exploration is focused in this area, and
(Fig. 26). The ridge was strongly inverted during the Late Jurassic, many more gas fields will be found here as the gas fields produce a
and basement gneisses and Karoo strata have been recovered in very good seismic amplitude response leading to high exploration
dredge samples around the ridge (Bassias & Leclaire 1990). Smaller success rates.
inversions along the Davie–Juan de Nova Ridge took place in the Farther south, around the Zambesi Delta in Mozambique to the
late Cretaceous until the late Tertiary. Tugela Cone in South Africa, there is less sediment fill, and both the
 The East African continental margin: a review
Fig. 26. Seismic section across the Morondava Basin (modified from Welch & Hyden 2005). The line location is shown in Figure 24.
 I. Davison & I. Steel

Jurassic and possibly Mid-Cretaceous source rocks may be in the oil Beckering Vinckers, J. & Davids, S. 2008. Exploration opportunities in the
window. Turonian–Albian age sources have not been tested in Tugela area, offshore the South African east coast. Poster presented at the
AAPG African Energy Global Impact Meeting, 28–29 October 2008, Cape
deeper waters along the southern part of the margin. Bright Mid- Town.
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the Cretaceous shelf break, suggesting that condensed organic facies C. & Maioli, F. 2017. Sedimentology and architecture of deepwater turbidite
systems offshore Mozambique-from concept to application. PESGB/HGS
may be present (fig. 10 in De Buyl & Flores 1986; Schlüter & 16th African E & P Conference, 31 August–1 September 2017, London,
Uenzelmann-Neben 2008). These source rocks would be produced Abstract Volume, 55–56.
by cold-current upwelling and preservation of organic material off Besairie, H. 1972. Geologie de Madagascar I: Les terrains sedimentaires. Annales
Geologique Madagascar, 35, 1–463.
the palaeo-Cretaceous shelf edge in >200 m water depth (anoxic).
Boast, J. & Nairn, A.E.M. 1982. An outline of the geology of Madagascar. In:
No wells have drilled down to this level east of the Cretaceous shelf Nairn, A.E.M. & Stehli, F.G. (eds) The Ocean Basins and Margins: Volume
edge, so the existence of this source rock remains hypothetical. 6. The Indian Ocean. Plenum Press, New York, 649–696.
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systems of the East African coastal basins. Presented at the 8th PESGB/HGS
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sequence stratigraphy. In: Watkins, J.S., Zhiqiang, F. & McMillen, K.J. (eds)
explorationists. Geology and Geophysics of Continental Margins. American Association of
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which could be potential oil-prone source rocks. Jurassic source tunities Mozambique Basin. Presented at the AAPG Annual Convention
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buried, and large rotated fault blocks at the Jurassic level were internationalpavilion.com/Mozambique.html
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Acknowledgements Colin Reeves kindly provided access to much of the Calais, E., Ebinger, C., Hartnady, C. & Nocquet, J.M. 2006. Kinematics of the
dyke data shown on Figure 3. Theo Faull and Eoin O’ Beirne are thanked for help East African Rift form GPS and earthquake slip vector data. In: Yirgu, G.,
with compilation of some of the map data. Matthew Taylor is thanked for Ebinger, C.J. & Maguire, P.K.H. (eds) The Afar Volcanic Province within the
compiling the Karoo correlation panel in figure 2 of the Supplementary material East African Rift System. Geological Society, London, Special Publications,
and for allowing this to be reproduced. New Age (African Global Energy) Ltd are 259, 9–22, https://doi.org/10.1144/GSL.SP.2006.259.01.03
thanked for permission to reproduce Figure 11. ION Geophysical are thanked for Catuneanu, O., Wopfner, H., Eriksson, P.G., Cairncross, B., Rubidge, B.S.,
permission to show the seismic data in Figures 6 and 25. Will Parsons is thanked Smith, R.M.H. & Hancox, P.J. 2005. The Karoo basins of south-central
for permission to reproduce the cross-section in Figure 21. Phil Copestake is Africa. Journal of African Earth Sciences, 43, 211–253.
thanked for permission to reproduce Figure 19. Duncan Macgregor, David Boote Chavez Gomez, S. 2000. Interpretation of the IGRF Corrected Aeromagnetic
and an anonymous reviewer provided very insightful reviews which have helped Map of Zimbabwe with Superimposed Geological Contacts. Unpublished
to improve this paper. report, Department of Earth Resources Surveys. International Institute for
Aerospace Survey and Earth Sciences (ITC), Delft, The Netherlands.
Chorowicz, J. 2005. The East African rift system. Journal of African Earth
Sciences, 43, 379–410.
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