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
Hydrocarbon exploration was fairly limited along the East African margin until 2010, with less than 60 offshore wells drilled before the major gas discoveries in the Rovuma Delta and Mafia Basin. There has been a flurry of exploration activity since, resulting in the discovery of more than 200 Tcf (trillion cubic feet) of recoverable gas reserves. This has led to large numbers of detailed papers and company presentations on the margin. This paper reviews this vast array of public domain information and attempts to summarize the geological evolution of the East African margin, including the Seychelles and the west coast of Madagascar, and briefly assesses the hydrocarbon potential (see Fig. 1 for the area covered).
Rift basins along the East Africa margin, colour coded by rifting phase and deltas. East Africa rifts partly from Chorowicz (2005).
Tectonic history of East Africa
Rifting events
The East African margin had a complex rifting history during at least five discrete phases which have different trends (Fig. 1):
Karoo age (c. 315 – 195 Ma, Late Carboniferous–earliest Jurassic) long-lived rifting with variable trends from NE to NNW (Catuneanu et al. 2005).
Early to Mid-Jurassic rifts (c. 183 – 170 Ma, Late Pliensbachian–Early Bajocian age; precursor to ocean spreading) with poorly defined trends, but the Mandawa, Morondava and Majunga basin trends are NE to NNE (Quinton & Copestake 2006; Papini & Benvenuti 2008).
Oxfordian–Valanginian rifts (c. 163 – 133 Ma) in South Africa developed during southern South Atlantic rifting, trending WNW oblique to the dextral Agulhas–Falklands Fracture Zone (Beckering Vinckers 2007).
Early Cretaceous rifts (Xai-Xai and Palmeras in the south, and the Anza and Maridadi in the north), both trending NW–SE; exact ages are not known and it is not clear whether these were caused by the same event (De Buyl & Flores 1986).
Late Cenozoic offshore rifts (c. 5 – 0 Ma; Querimbas and Lacerda rifts, which are an extension of the East Africa Rift System) (Franke et al. 2015).
The margin is also further complicated by Jurassic rifting having occurred obliquely to the margin followed by seafloor spreading which opened north–south, creating transform and transtensional zones of late rifting (see the Supplementary material).
Karoo rifting phase (Carboniferous–Early Jurassic)
Pan African age (c. 1000 – 550 Ma) mobile belt weaknesses exerted a strong control on the orientation of the Karoo rifts in the onshore area (Fig. 2). The location and orientation of the offshore Karoo rifts is still poorly known because they are deeply buried, and difficult to image on seismic reflection data. The major Pan African age mobile belts are generally orientated parallel to the East African coastline, and the Karoo rifts can be expected to be coast parallel (Fig. 2). Karoo basins developed in cold arid climates in Late Carboniferous–Early Permian times, during the foreland basin development in South Africa, with the climate becoming warmer and wetter in Late Permian–Triassic times during the main Karoo rifting phase (Catuneanu et al. 2005). The early Karoo sediments are dominated by glacial deposits, sandstones and shales. Late Permian coals and some thin organic-rich algal (oil-prone) shales occur throughout the southern rifts of Africa, with two correlatable organic-rich horizons of Artinskian and Capitanian age (see the Supplementary material). There was an important marine transgression at the start of the Triassic in Madagascar which coincides with the initiation of the main Karoo rifting event. The preserved Karoo sequence generally reaches up to 2 – 4 km in thickness (Catuneanu et al. 2005). Many oil seeps and oil shows in wells have been reported within the South African Karoo coalfields (Petroleum Agency South Africa 2008), but very little oil exploration has taken place in the onshore Karoo basins to date (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).
Jurassic rifting and the Bouvet hotspot
The Permo-Triassic Karoo rifting did not achieve break-up of Gondwana. A hiatus of some 10 myr was followed by the Early Jurassic rifting which commenced in the Late Pliensbachian (c. 185 – 183 Ma) and ended in the Mandawa Basin by the Aalenian (174 – 170 Ma: Quinton & Copestake 2006), but continued until the early Bajocian in Madagascar (c. 170 Ma: Besairie 1972). The oldest rift strata in the Majunga and Morondava basins are Early Toarcian (Besairie 1972), which consist of marine marls and limestone and evaporites, followed by Bajocian–Bathonian shallow-marine deposits. It should be noted that the duration and onset of rifting probably varies along the margin, and there are still only a few areas that have been sampled and dated. It is no coincidence that the Bouvet hotspot developed at the same time as the successful rifting that proceeded to break-up. The hotspot created a vast system of continental flood basalts, dyke swarms and elongate volcanic complexes (seawards-dipping reflectors) composed of the following (Fig. 3):
Karoo-Ferrar basalt fields in Africa, Antarctica and Australia (183 Ma, Pliensbachian: Duncan et al. 1997);
WNW–ENE-trending Okovango (Botswana) dyke swarms (178 Ma: Le Gall et al. 2002, 2005);
north–south-trending Lebombo monocline volcanics and coast-parallel dyke swarms (dated at 182.1±2.9 Ma: Riley et al. 2004; Klausen 2009), and NE–SW-trending Mwenetzi volcanics and dyke swarms (Jourdan et al. 2004).
The Lebombo and Mwenetzi volcanics have been interpreted as seawards-dipping reflector sequences (SDRs) (Klausen 2009; Davison & Steel 2016), which form a pre-drift conjugate pair with the Explora wedge volcanics in Antarctica (Hinze & Krause 1982; Kristoffersen et al. 2014). The Lebombo volcanic belt is, on average, 35 km wide and lava-bedding dips progressively increase eastwards from 10° E to 40° E due to synmagmatic rotation (Klausen 2009) (Fig. 4a). Dyke injection varies from perpendicular to bedding, to 60° to bedding and consistently dipping westwards, suggesting synvolcanic rotation has occurred. Up to 50% of the section can be dykes (Fig. 4a) (Klausen 2009). Along their eastern edge, the lavas dip underneath the overlying Lower Cretaceous clastic sediments. Lavas were encountered at 3.2 km depth in the Domo-1 well which lies c. 300 km east of the Lebombo monocline exposures (Fig. 4b). The conjugate wedge in Antarctica also has an estimated width of 220 km (Kristoffersen et al. 2014). Hence, the Mozambique plain may be floored by SDRs and oceanic crust (see also Franklin et al. 2015). SDRs are also present in the Angoche Basin and east of the Beira High (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.
(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.
Opening history of the East African Indian Ocean
Initiation of ocean spreading of the West Somali–Madagascar Basin is not clearly defined, and may have started as early as 183 – 177 Ma (Eagles & König 2008; Reeves 2016); but may have been as late as 165 Ma, shortly after the rifting ceased in the Aalenian–early Bajocian in Madagascar (Papini & Benvenuti 2008). The widespread marine flooding in the Toarcian could be synchronous with spreading, although localized rifting still may have continued after this.
The position of the extinct mid-ocean ridge between Madagascar and Africa was not easily defined by either gravity or magnetic data as it is buried below a thick pile of sediment (5 km) and Cenozoic volcanics (cf. Cochran 1988 and Eagles & König 2008). However, recent satellite gravity data (Sandwell et al. 2014) better defines the fracture zones and the mid-ocean ridge is clearer (Davison et al. 2015; Phethean et al. 2016) (Fig. 5). The ocean–continent boundary (OCB) positions in Figure 5 have been estimated using the long offset, deep seismic reflection imaging (Danforth et al. 2010, 2012) as well as the new satellite gravity data. There is approximately 1700 km of oceanic crust preserved between Africa and Madagascar (measured parallel to the fracture zone trend). Estimates of full spreading rates vary from 5.4 cm a−1, if spreading started at 165 Ma and ceased at the M10n anomaly (135 Ma: Norton & Sclater 1979), to 3.5 cm a−1 if spreading ceased at 118 Ma (M0 anomaly: Segoufin & Patriat 1980). Davis et al. (2016) estimated that spreading ceased at 120.8 Ma using new magnetic data.
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).
The Falklands Plateau of South America fitted snuggly against the transform margin of South Africa until Hauterivian–Barremian times when the South Atlantic Ocean opened. The Agulhas–Falklands Fracture Zone lies south of the west African marginal basins in South Africa, but comes very close to the eastern South African margin in the Transkei Basin, which is a true transform margin. The Transkei has poor hydrocarbon potential because any potential Jurassic or Cretaceous source rock would be likely to be immature as the sedimentary infill is usually less than 2 km (Schlüter & Uenzelmann-Neben 2008).
The Seychelles and India are thought to have separated from Madagascar around 88 Ma, when the Marion hotspot initiated, which was centred in southern Madagascar (Storey et al. 1995). The Seychelles and the Mascarene Ridge were separated from India around 70 – 65 Ma, when the Carlsberg Ridge initiated and the Deccan flood basalt province was formed (Duncan & Pyle 1988; Van Hinsbergen et al. 2011; Reeves 2016). After separation, the Seychelles rotated anticlockwise in the Palaeogene, which caused plate compression but not necessarily subduction along the Amirante Banks (Eagles & Hoang 2014).
Early Cretaceous rifting
The Lamu Embayment and Maridadi Trough are offshore extensions of the Anza Graben, where the initiation of rifting is dated as Neocomian, but extension continued with Cenomanian–Maastrichtian and Early Tertiary rifting phases (Bosworth & Morley 1994; Morley et al. 1999). A section through the offshore area in the vicinity of the Simba-1 well in Kenya indicates a well-defined fanning stratal wedge attributed to the Early Cretaceous rifting (Fig. 6). The total Jurassic–Early Cretaceous age stratal thickness may reach up to 10 km in this area. Elsewhere along the margin, Early Cretaceous rifting also occurred in southern Mozambique with the development of the Albian–Aptian age Xai-Xai Graben and several other parallel half-graben (De Buyl & Flores 1986; INP Instituto Nacional de Petroleos Mozambique 2011) (Fig. 1).
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.
Late Cretaceous magmatism in Madagascar
Basaltic and rhyolitic lavas and dolerite sills occur throughout onshore Madagascar; and sill intrusions and basalts have been encountered in offshore wells in the Morondava Basin (Bardintzeff et al. 2001). The Marion hotspot was believed to have been centred over SW Madagascar, and volcanic ages range from 91.6±0.3 to 83.6±1.6 Ma (Storey et al. 1995; Torsvik et al. 1998). The ages of the magmatism corresponds to the break-up of Madagascar from India, again suggesting that plume weakening led to continental break-up.
Tertiary rifting
The East African Rift began to develop soon after the Afar Plume volcanics were erupted at c. 30 Ma (Baker et al. 1996). The rift propagated southwards, and bifurcated into an eastern and western branch over the next 20 myr until it finally propagated offshore (Franke et al. 2015; Macgregor 2015) (Fig. 7). Two branches of the East Africa Rift extend into the offshore region in Mozambique, with the eastern branch forming the offshore Pemba–Tembo–Zanzibar trough system and continuing southwards to the Querimbas-Lacerda Graben (Mougenot et al. 1986; Franke et al. 2015; Mulibo & Nyblade 2016) (Fig. 1). These graben appear to be caused by reactivation of the Davie Transform and associated subsidiary north–south-trending faults. The western branch of the 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 (Macgregor 2015) (Figs 1 and 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 Zanzibar, Pemba and Tembo troughs contain Neogene sediment up to 5 – 6 km in thickness, but the exact age of the strata is not known (Kejato 2003; Parsons et al. 2013). The offshore active rift segment in the Querimbas Graben, has boundary faults with 1.5 km of offset at the seabed; even though this lies at the downslope front of the Rovuma Delta where sedimentation rates are high (McDonough et al. 2016). Deformation in this graben is very late with very little evidence of sedimentary growth thickening into the graben until the Pliocene (Franke et al. 2015). The East African Rift is currently very active along its whole length, and is extending at a rate of 4 cm a−1 in the north and 2 cm a−1 in the south (Calais et al. 2006) (Fig. 7).
The shoulder uplift of the East African Rift resulted in a large amount of denudation from 30 Ma to Recent, resulting in the large deltas in Somalia, Rufisque (Tanzania) Rovuma and Zambesi (Mozambique), and the Tugela Cone (South Africa: Fig. 1). The Lamu-Juba and Rovuma deltas have well-developed compressional toes due to gravity gliding in Late Cretaceous–Late Tertiary times, whereas the Zambesi and Durban deltas are relatively undeformed, with limited extensional faulting and only very localized compression at the toe.
Tertiary magmatism
Two parallel hotspot trails of Tertiary age are present in the Indian Ocean (Fig. 8). The northern trail extends from the Seychelles to Grande Comore Island, and even possibly to the outer Rovuma Delta where a circular bulge 300 km in diameter is observed at the seabed (Sayers 2017). Recent volcanism is also associated with this bulge along the eastern margin of the Querimbas Graben. The other hotspot trail extends from the Nazarene Bank to Reunion (Fig. 8). The Seychelles volcanism commenced around 50 – 40 Ma and the hotspot is still active, centred over the Grande Comore Island (Emerick & Duncan 1982). The southern trail initiated around 30 Ma on the Mascarene Bank and continued to Mauritius, and is currently active on Reunion Island.
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.
The main geological events that affected the East African margin are summarized in Figure 9. The geology and hydrocarbon potential of the individual basins are now described from south to north.
Geological events summary chart for the East African margin.
Algoa and Gamtoos rifts
Introduction
The Algoa and Gamtoos rifts were developed along the Agulhas Transform Zone in Late Jurassic–Early Cretaceous times, when the Falklands Plateau of South America separated from the African margin. The rifts trend WNW, and extend onshore into the 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 200 m water depth. Oil shows were encountered in at least two wells. Pioneer drilled the Hb-Q1 well in November 2000, and there have been no further wells since.
(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).
Stratigraphy
Rifting commenced in the Oxfordian and continued to the Valanginian, with lacustrine clastics deposited with potential source rocks and reservoirs (Thomson 1999). There was a marine incursion at the end of rifting, when shallow-marine clastics were deposited (Beckering Vinckers 2007). The end of rift unconformity is overlain by Hauterivian strata. A substantial amount of erosion occurred at this time indicating uplift of the shelfal area, which may have been associated with the impingement of the Etendeka-Paraná plume on the South Atlantic margin. The Algoa Canyon is a major erosive channel feature that was incised in the Barremian–Aptian and filled by Aptian–Albian age clastics (Fig. 10b). South Africa was uplifted in the Oligocene by a mantle hotspot (South African Superplume) which continues to the present day underneath South Africa, with accelerated erosion and clastic deposition in the offshore from 30 Ma to the present day (Burke & Gunnell 2008).
Structure
This is a dextral transtensional margin which opened up with right-lateral shear movement along the future Agulhas–Falklands Transform. The WNW-trending late Jurassic–Early Cretaceous rift graben reach up to 4 km deep, and they are filled with lacustrine clastics which are dominated by conglomerates and sandstone in the 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 faults (Paton 2006), but farther offshore graben have closely-spaced normal faults with an approximate spacing of 3 – 4 km, creating many small structural traps in the synrift strata. There is an outer basement high along the Agulhas transform margin which may have caused the basins to be restricted even during the early drift phase.
Source rock
Kimmeridgian–Berriasian rift-phase source rocks have been identified in the onshore Sundays River Trough, with 3 – 4% total organic carbon (TOC) and hydrogen index (HI) values up to 500, which are up to 170 m in thickness (Van der Spuy 1997). The Port Elizabeth Trough also contains marine shales of a similar age with 1.3 – 3.5% TOC and HI of 150 – 440. Excellent quality source rocks have been proven in the DSDP wells, which are located on the Maurice Ewing Bank. This was adjacent to South Africa from Upper Jurassic to Valanginian times. The DSDP 330 well encountered good source rocks of Mid-Albian (drift phase), Barremian–Aptian (late rift to drift) and Late Jurassic ages with >100 m thickness of marine shales containing TOC values of 2 – 6% (DSDP 1989).
Maturity
Present-day heat flow in the offshore area is estimated to be around 45 – 55 mW m−2 with the Ha-B2 well reaching 65 mW m−2 (Goutorbe et al. 2008). This is a fairly low heat flow, suggesting that present-day geothermal gradients will be in the region of 25 – 30°C km−1 and the present-day oil window will only be reached at greater than 4 km burial depth.
Reservoirs
The onshore southern Cape Fold Belt comprises thick sequences of pure quartzites that were folded and metamorphosed during the Permian age Cape Orogeny which developed a large mountain belt. Erosion of the Palaeozoic quartzites will have sourced high-quality reservoir sandstones during the basin development. The synrift Berriasian–Valanginian sandstones have variable porosities, but often exceed 25% (Beckering Vinckers 2007). Portlandian and Kimmeridgian sandstones tend to be more argillaceous, with reduced reservoir quality of 9 – 25% porosity. Barremian–Lower Albian sandstones also have a good reservoir potential.
Hydrocarbon potential
This basin has good potential for new plays, including stratigraphic 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 encountered in the well in the interval correlated to bright reflectors, which gradually increase in amplitude updip away from the well (Fig. 11). There are also stratigraphic traps in the Algoa Canyon with sidewall traps outside the canyon, which may be sealed by shale-fill in the canyon.
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.
Durban Basin and Tugela Cone
Introduction
This basin lies along the eastern termination of the Agulhas Fracture Zone where the continental shelf widens suddenly (Fig. 12). The Tugela River has produced a delta in this area which initiated in Late 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: Singh 2003).
Map of the Durban Basin.
Stratigraphy
The synrift stratigraphy has been tested on the footwall highs in two of the wells, with thin sandstones and shales encountered. The shallow rift areas are mainly sand-prone, but better source rocks shales can be expected in the deeper half-graben that are undrilled. The drift sequence consists of deep-water clastics with basin-floor fans and turbidite channel sandstones expected.
Structure
Rifting probably started in Early Cretaceous times associated with South Atlantic opening. The extension was initially slow so that the basal rift section covered the crest of the fault blocks. This was followed by rapid rifting with 3 km of wedge-shaped fill, which thickens into the hanging-wall graben. Drape over the footwall high blocks has created traps in post-rift Cretaceous sediments where bright amplitude anomalies have been detected (Battacharya & Duval 2016).
Source rocks and maturity
The Jc-D1 well encountered oil shows in synrift sandstones which are believed to have been derived from Upper Jurassic marine source rocks (Beckering Vinckers & Davids 2008). Similar aged source were encountered in DSDP 330, with 150 m of 3 – 5% TOC 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 chimneys and chemotropic mounds are observed on seismic data (Van der Spuy 2009). An Aptian source rock may also be present.
Reservoir
Synrift lacustrine sandstone reservoirs can be expected in the rotated fault block traps.
Basin-floor fans of Mid-Cretaceous age have also been postulated (Dolphin and Camel leads) in the deep water that lies close to a potential source rock (Beckering Vinckers & Davids 2008; Impact Oil & Gas Ltd 2014).
Hydrocarbon potential
Structural traps are present at the synrift level and in the Early to Mid-Cretaceous strata, which are draped over the underfilled fault blocks. Stratigraphic pinch-out traps are also predicted (Beckering Vinckers & Davids 2008) (e.g. Fig. 12). This is a rank frontier basin, but has potential for oil-prone source rocks. There are no deep-water wells drilled to date.
South Mozambique Basin
Introduction
The South Mozambique Basin is a large basin which has two commercial onshore gas fields, Pande (3.4 Tcf in place) and Temane (1.8 Tcf in place), and two undeveloped fields, Buzi with 2P reserves of 0.283 Tcf and the Njika Field (Fig. 13) (Boote & Matchette-Downes 2009; www.energy-mp.com). Inhassoro has recently been declared commercial by Sasol, although recovery will be difficult as there is only a thin condensate/oil rim below the gas cap.
Map of the South Mozambique Basin.
Stratigraphy
Volcanics and interbedded sandstones were encountered at the base 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 Maputo Formation are overlain by the Lower Domo Formation which contains dark grey marine shales that are probable source rocks. Palaeogene–Miocene (Cheringoma) shelf carbonates are present in the onshore area (Zacarias 2009).
Structure
The whole of the southern Mozambique plain may be floored by Jurassic volcanics which lie on Karoo strata along the western edge, but may be oceanic crust farther east. Early Cretaceous rifting phase produced the NNW-trending Xai Xai Graben, and other parallel rifts onshore (Fig. 13). BP drilled the Xai Xai-1 well in the graben; but the well was dry, probably due to an immature or absent Albian age Lower Domo source. The other onshore graben are also believed to be shallow (1 – 3 km), so their hydrocarbon potential is poor. Slight folding occurred in the Late Cretaceous–Palaeogene strata offshore which has created the subtle Pande and Termane gas field structures (Mabote 2008). Late Tertiary rifts at the southern termination of the East African Rift System affect southern Mozambique, with the Urema and Chissenga graben extending into the offshore, and several north–south-trending graben cutting though the coastal plain west of Pande and Termane fields (Fig. 13).
Source rocks and maturity
Early Cretaceous Domo shales are the principal source rock that has been identified. De Buyl & Flores (1986) indicated TOC levels of only 1%, but there is no detailed source information published. The gas in the Termane, Pande, Inhassoro and Nijika fields is believed to be thermogenic, and derived from the Domo shales (Loegring & Milkov 2017). Oil samples from the Termane and Inhassoro fields have geochemical signatures indicative of marine shale, with high gammacerane indicating a hypersaline source possibly from the Domo shales (Loegring & Milkov 2017).
Reservoir
Late Cretaceous nearshore marine sandstones (Grudja Formation) are the main reservoirs in the Pande, Buzi, Temane and Inhassoro fields (Matthews et al. 2001). Domo Formation sandstones are also productive in Nemo-1. Shallow-marine carbonates of the Cheringoma Formation (Paleocene–Miocene age) may also be potential reservoirs.
Hydrocarbon potential
The drift section in the offshore area is relatively unstructured, and this is probably why there are no deep-water wells for over 1000 km along the South Mozambique margin. The Inhassoro-9z well flowed a total of 200 000 barrels (bbl) of oil on an extended well test, indicating significant potential for oil in this part of the basin (Trueblood 2013). There is potential for further discoveries around the existing fields. However, the Early Cretaceous graben farther west (e.g. Palmeiras and Xai-Xai) are believed to be immature for oil generation (shallow burial) and no effective source rock has been proven so far. The offshore area of southern Mozambique has a fairly thin Jurassic–Cretaceous sequence of approximately 3 s two-way time (TWT) equivalent to c. 4 km, so source rocks may be in the oil window. Structural traps have been identified on seismic data with Early Cretaceous sediments draped over underlying rift fault blocks (Salman & Abdula 1995).
Zambesi Delta and Angoche Basin
Introduction
The Zambesi River has a very large catchment area which has fed the offshore Zambesi Delta. North of the delta, the margin is known as the Angoche Basin (Fig. 14) (Mahanjane et al. 2014). The delta has a maximum sedimentary thickness of c. 11 km, and it is bounded by the Beira High which lies at the seawards edge of the delta (Branquinho 2008; Mahanjane et al. 2014) (Fig. 15). Thick sediment has spilled around the high and deposited to the east of the Beira High. Incipient oceanic crust may have formed along the landwards side of the Beira High. Seismic refraction data suggest thin dense crust NW of the Beira High, which is thought to be oceanic SDRs, or highly thinned continental crust, with dense underplating of new igneous material (Mueller et al. 2016).
Map of the Zambesi Delta and Angoche Basin.
Seismic line through the Zambesi Delta and the Beira High. From INP Instituto Nacional de Petroleos Mozambique (2014).
Stratigraphy
The Zambesi Delta consists of prograding marine clastics which were deposited in three periods of enhanced sedimentation during the following periods: Late Cretaceous (90 – 66 Ma), Oligocene (34 – 23 Ma) and Late Miocene–Recent (10 – 0 Ma) (Walford et al. 2005). The catchment area of the Zambesi is believed to have doubled in size in the Pliocene. The Oligocene–Recent part of the delta reaches 4 km in thickness and covers an area of 200 000 km2. The deep-water Angoche Basin has not been drilled but there are seismic lines that have tied to the DSDP 242 borehole which indicate thick sedimentation with c. 3 km of Cretaceous strata and 3 km of Tertiary–Recent strata (Francis et al. 2017, fig. 3).
Structure
The Angoche Basin appears to be mainly floored by oceanic crust which has been imaged on seismic data, and seismic refraction data also support this (Leinweber et al. 2013; Mahanjane et al. 2014; 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 Angoche Basin and east of the Beira High (Fig. 15) (Francis et al. 2017; Leinweber et al. 2013). The Angoche Basin is unstructured (Mahanjane et al. 2014; Francis et al. 2017), except for the transpressional segment along the Davie Fracture Zone which is marked by large overthrusted Jurassic sequences (Mahanjane et al. 2014).
Map of the Rovuma Basin.
The Zambesi Delta remained remarkably stable with little evidence of listric extensional faults or downslope toe compression. However, a minor detachment has been imaged at the Paleocene level (Mabote 2008). Mild Tertiary age tectonic inversion has occurred on the north side of the delta with Neogene strata observed onlapping onto a broad anticlinal structure (Mabote 2008). The lack of structuring perhaps explains why there are only five wells drilled in the onshore and shallow water, and no deep-water wells.
The Beira High appears to be a cored by 25 km-thick continental basement with rifted fault blocks clearly imaged on some seismic lines (Fig. 15) (Salazar et al. 2013; Mueller et al. 2016). Structural closures are present around the Beira High in rifted terrace blocks adjacent to potentially mature source rocks, and with large structural closures on the high.
Source rocks and maturity
There is no information available on source rock potential of the Zambesi Delta. However, an onshore oil seep has been recorded at Angoche (Fig. 14). The ODP Leg 113 well 692B on the conjugate Antarctica margin penetrated 45 m of Valanginian source rocks containing Type II marine kerogen, with an average of 9.8% TOC and HI of 300 – 600 (Thompson & Dow 1990). Heat flows of 60 – 70 mW m−2 have been measured from the onshore Divinhe-1 and Mambone-1 wells (Mahanjane et al. 2014).
Reservoir
Deep-water turbidite sandstones can be expected throughout the Late Cretaceous–Miocene section, and high amplitude-discontinuous 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.
Hydrocarbon potential
The Zambesi Delta has potential for many stratigraphic traps with channel sandstones. The large thickness of Tertiary sediment would place any potential Mid-Cretaceous source rocks into the oil window. These source rocks have not been encountered to 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 mid-Cretaceous section which pinch out onto the Cretaceous 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, so stratigraphic traps will be the main targets. Most of the Angoche Basin also lacks any structure at shallower levels, and stratigraphic traps will be the main targets. However, it is very highly structured along the Davie Fracture Zone, where transpressional thrusts were developed during the Late Jurassic, and both clastic reservoir and source rocks may be developed (Mahanjane 2014).
The Beira High has potential for very large structural closures in rotated fault blocks and drapes over the high. The sediments are thick (5 – 6 km) around the sides of the high, so any potential Mid- or Early Cretaceous sources may be in the oil window.
Rovuma Basin
Introduction
The Rovuma Delta straddles the Tanzania–Mozambique border. Recent giant gas discoveries have fuelled exploration along this margin (Fig. 16). The Rovuma Basin continues 200 km south of the delta as the Cabo Delgado and Lacerda sub-basins. The Cachalote subcommercial gas discovery in 2013 highlights the potential of the margin to the south of the Rovuma Delta (Fig. 16).
At least 200 Tcf of gas in place has now been proven in the deep-water area of the Rovuma Delta (Wentworth Resources Ltd 2015). Wells have also been drilled in the shallow water and onshore part of the delta, where extensional listric faults and rollover anticlines are the main traps. These traps contain the Ziwani, Mnazi Bay and Ntorya gas fields, but these are considerably smaller than the offshore fields (Aminex plc 2015; Wentworth Resources Ltd 2015).
Stratigraphy
Karoo and Jurassic rifts are present around the Ibo High area and probably underlie the delta, they are presumed to source the thermally-generated dry methane gas. The onshore stratigraphy has been tested down to the Aptian–Albian in the Mocimboa-1 well, which encountered marine marls at 3.3 km depth and had oil shows in Cretaceous sandstones. The Jurassic and Early Cretaceous sections have not been drilled offshore; the deepest drilled strata are Late Cretaceous clastics. The Rovuma Delta developed from Late Cretaceous times and is still a site of major deposition from the Rovuma River (Key et al. 2008). The Late Cretaceous Mifume Formation consists of prograding clastics which are mainly sandstones and conglomerates in the shallow proximal part of the basin, grading to distal mudstones and marls reaching up to 810 m thick in the Mocimboa-1 well (Key et al. 2008)
Structure
The shallow shelf area of the Cabo Delgado Sub-basin contains several prominent basement highs that make up the regional Ibo High trending north towards the Rovuma Delta (Fig. 16). Several downthrown fault terraces have prospective structural traps which may require updip fault seal at Karoo, and Upper and Mid-Jurassic levels. Onlapping stratigraphic traps have potential at Lower Cretaceous levels surrounding the high.
The offshore Rovuma Delta is affected by three cells of updip listric faults and downdip linked compressional toes (Palma, Lunique or Mocimboa and Medjumbe: Law 2011; Mahanjane & Franke 2014) (Fig. 16). The toe thrusts and anticlines first attracted explorationists, but the largest gas fields are trapped below the detachment surfaces, and in front of the delta in stratigraphic traps (Cove Energy plc 2011; Law 2011). There are also small gas deposits in the toe thrust anticlines, but these are smaller than the sub-detachment fields. The main detachment level is within the Eocene shales, with a subsidiary Oligocene detachment above. The main sliding occurred in the Oligo-Miocene, and minor movement continued until the Mid-Pliocene.
The Querimbas and Lacerda (or Nacala) graben are the offshore 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 last 5 myr (Franke et al. 2015). However, older Jurassic age rotated fault block traps are also present in the graben; and also further east of the Querimbas Graben, in the Comoros territory (Singleton et al. 2014). It is not clear whether western Comoros is continental or rifted oceanic crust, but the graben are small and probably situated on extended oceanic crust (Fig. 17) (see also Phethean et al. 2016). The Querimbas Graben cuts across the distal part of the Rovuma Delta, and sediment is diverted to flow north–south down the graben axis (McDonough et al. 2016). Despite the rapid sedimentation rate expected at the delta front, the tectonic subsidence outpaces the sediment deposition and the seafloor is offset by over 1 km.
Line drawing through the Rovuma Delta and Querimbas Graben, offshore Tanzania and Comoros. The line location is shown in Figure 16.
Reservoirs
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 well (Cove Energy plc 2011; Law 2011; Palermo et al. 2014; Bendias et al. 2017). Net pay thicknesses vary from c. 30 to 200 m, with high net:gross, excellent porosities and permeabilities. The high quality of the thick reservoir sandstones is attributed to flow stripping of the turbidite flows due to strong northwards-directed contourite currents which take out the fines to produce thicker mud levees on the northern side of the channels and a clean sand infill within the channels (Palermo et al. 2014).
Source rocks and maturity
The gas is >96% methane in Mnazi Bay (RPS Energy Canada Ltd 2013) and in the offshore giant fields. The source of the Rovuma dry gas fields is believed to be either Jurassic or Triassic (Karoo) shales, but it is not clear whether this is an original gas-prone source or an overmature oil-prone source. Farther south, the Mecufi and Pemba onshore oil seeps hint at oil-prone source rocks in the Jurassic and possibly Karoo sediments. Therefore, the area west of the Ibo High has a better potential for oil compared to the Rovuma Delta, where only gas is present.
Hydrocarbon potential
The best potential for future finds is in the downthrown terraces and stratigraphic pinch-outs surrounding the Ibo High trend. Several important oil seeps have been identified along the coastline west of the Ibo High, indicating potential oil source presence (Fig. 16). Although it should be noted that the Cachalote gas discovery is also in this area. The presence of rifts at basement level east of the Davie Fracture Zone is potentially important (Fig. 18b), as this may imply that there are possible Jurassic source rocks present in this area, which are buried into the oil window, so that the exploration blocks in the Comoros Islands may have some hydrocarbon potential (Fig. 18) (Craven 2015; Roach et al. 2017). However, these are generally fairly small with 2 km of reflective strata that may be volcanics deposited on oceanic crust (see the following discussion on the Mafia Basin).
Map of the Mafia and Mandawa basins.
Mafia and Mandawa basins
Introduction
The offshore Mafia Basin is bounded to the north by Mafia Island, the Rovuma Delta to the south and by the Davie Ridge Transform to the east. The onshore portion of the basin is known as the Mandawa Basin, which is separated from the offshore by the Pande Kizimbani High (Fig. 18).
The northern limit of the onshore Mandawa Basin is bounded by an east–west transfer fault, and to the south the basin probably extends and is buried underneath the Rovuma Delta. BG have discovered more than 15 Tcf of gas in the Mafia Basin and estimate a recovery factor of 60 – 80%, and Exxon-Mobil have an estimated 22 Tcf of gas in place in Block 2 (Offshore Energy 2013; 2b1st Consulting 2015). Most of the gas is dry, but Mzia-1 contained condensate in Block -1, where oil may have been generated first but was then forced out of the reservoir by later gas generation.
This area is conjugate to the Morondava Basin of Madagascar where high-quality source rocks have been encountered in the Permian Sakamena Shales, which source the Bemolanga tar sands. Twenty wells (only seven with total depths (TDs) >1000 m) have been drilled in the onshore Mandawa Basin, but with no discoveries, although three wells (Mita-Gamma-1, Mandawa-7 and Mbate-1) had oil shows (Quinton & Copestake 2006).
The main structural feature in the offshore area is the sinistral transcurrent Sea Gap Fault, which now has a north–south-trending string of >10 gas fields discovered in structural traps along the fault (Higgins & Sofield 2011; Ophir Energy 2016) (Fig. 18). Two major gas fields have been discovered in Paleocene fans in the 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: Fig. 18).
Stratigraphy
The synrift stratigraphy is well documented in the Mandawa onshore basin (Quinton & Copestake 2006). Pliensbachian strata consist of basal sandstones overlain by Mbuo clastics and the Nondwa halite of Toarcian age. The overlying sequence is mainly shallow-marine limestones and clastics of Upper–Middle Jurassic age. The Cretaceous sequence comprises fine-grained clastics and occasional limestones. Offshore, the Mafia Basin contains greater than 7 km of Cretaceous–Recent clastic sediment fill, which is up to 5 km thick east of the Davie Ridge. In the offshore Mafia, the wells have only penetrated down to the Late Cretaceous, which is a deep-water clastic sequence.
Structure
The onshore Mandawa Basin rifting initiated in the Pliensbachian and probably continued into the Late Jurassic. The main rift faults are orientated north–south, but there are important ENE–WSW-trending transfer faults present in the basin and one of these marks the northern limit of the basin.
Toarcian salt produced decoupling of the basement involved rift faults, and large post-salt listric faults sole out on the salt horizon (Hudson 2011) (Fig. 19). Salt diapirism occurred through the Jurassic into the Cretaceous. The offshore Mafia Basin may also contain thin salt, but this has not been identified on the seismic data so far. There is a small thickness of Cretaceous and Tertiary sediment onshore; and the basin was uplifted and eroded some time prior to, or during, the Tertiary.
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.
In the offshore region, deep rotated Jurassic age? faults blocks can be imaged even east of the Davie Ridge, which is supposed to be a transform boundary separating oceanic and continental crust (Fig. 17). However, recent seismic data suggest this may be an ocean–ocean transform and the OCB lies farther west (Phethean et al. 2016). Other 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 single transform boundary but an amalgamation of subsidiary transforms (Phethean et al. 2016). The small size of the rifts and the high amplitude of the reflective fill east of the Davie Transform seems more indicative of faulted oceanic crust with a volcanic half-graben fill rather than Karoo age sediment in our opinion.
The Seagap Fault is a long-lived Jurassic–Recent fault with late sinistral strike-slip displacement (Higgins & Sofield 2011). It has created prominent positive flower structures, which trap a string of gas fields draped along the fault (Fig. 18).
Source rocks and maturity
Source rocks are potentially present in the Karoo sequence in the onshore Mandawa Basin, as oil shows were encountered in the pre-salt section in two wells. The Upper Nondwa Toarcian age salt contains thin interbedded shales with 3 – 9% TOC and HI values of 300 – 1000 with Type II/III kerogen (Kagya 1996; Quinton & Copestake 2006). However, the western part of the onshore basin contains less than 3 km of sedimentary section above the source rock interval and therefore the source may be immature. Nonetheless, the basin thickens towards the coastline and source rocks may be mature in this onshore area.
In the offshore Mafia Basin, the main source rock is believed to be either Karoo shale or synrift Jurassic age shales, which have sourced all the large gas discoveries. The Palaeogene also contains a waxy plant material source rock, but is thought to be immature over most of the basin. It is not known whether these source rocks also have oil potential or whether they are only gas-prone.
Reservoir
The onshore Songo Songo gas field has Neocomian Kapimatu and transgressive marine Albian sandstones. The offshore gas fields are in deep-water turbidite sandstones ranging from Albian to Eocene age (McDonough et al. 2016; Ophir Energy 2016). The Chewa well proved channelized sandstone reservoirs throughout the Paleocene–Miocene section, with porosities up to 30% and permeabilities >1 D (Sansom 2013).
Hydrocarbon potential
Potential stratigraphic traps have been mapped throughout the Mafia Basin on 3D seismic data and many more gas fields will probably be discovered (Fig. 18) (Ophir Energy 2016).
Most of the structural traps along the Sea Gap Fault have been drilled at shallow depths, but deeper reservoirs may have some potential. In the onshore Mandawa Basin, the key issue is that the best mature source rock is separated from the reservoirs by the intervening Toarcian salt.
Zanzibar Coastal Basin, and the Zanzibar, Pemba and Tembo troughs
Introduction
The Zanzibar, Pemba and Tembo troughs are located between the African mainland and the Pemba and Zanzibar islands (Fig. 20). The Sunbird-1 well discovered a small column of oil in a Miocene carbonate reef perched on the eastern margin of a Tertiary graben (Brown 2013; Pancontinental Oil & Gas 2014). The deeper offshore area to the east is named here as the Zanzibar Coastal Basin, which is believed to have a similar geology to the Mafia Basin immediately to the south. Several onshore wells have been drilled on the mainland and the islands, but these were dry. However, there are important oil seeps on Pemba Island (Maende & Mpanju 2003). There is only one deep-water well in this area, Mkuki-1, which encountered reservoir sandstones, but was dry (Fig. 20).
Map of the Zanzibar, Pemba and Tembo troughs, and the Zanzibar Coastal Basin.
Stratigraphy
The stratigraphy of the offshore is only known down to the Late Cretaceous from the Pemba-5 well. The shallow basin is expected to contain deep-water clastics in the Cretaceous interval, shallowing to deltaic sandstones and shales in the Palaeogene (Nelson 2006). The deep-water rocks are expected to be clastics, similar to the Mafia Basin strata. The basin fill in the Zanzibar, Pemba and Tembo troughs are Tertiary clastics and carbonates which may reach up to 8 km in thickness (Fig. 21) (Parsons & Nilsen 2012; Parsons et al. 2013). The Zanzibar-1 well was drilled on the western edge of the Zanzibar Trough and encountered Paleocene sandstones and shales, overlain by Eocene marine clastics and limestones, followed by Neogene clastics.
Cross-section through the Pemba Trough. From Parsons et al. (2013). The line location is shown in Figure 20.
Structure
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. The localized Neogene Zanzibar, Pemba and Tembo troughs broadly trend north–south and form a right-stepping en echelon pattern. The troughs may be associated with transtensional strike-slip movement along north–south-trending faults, and faulting is still active with offsets at the seabed. The two islands of Pemba and Zanzibar are basement-cored highs. The Pemba High is covered by thick Palaeogene deltaic strata, suggesting that this is a Neogene feature caused by inversion.
Source rocks and maturity
Prominent oil seeps are present on the Pemba and Nyuni islands (Matchette-Downes 2003) and on the mainland in the west of the Pemba Trough (Afren 2014). Farther south, the Wingagonyo tar sand is believed to be a palaeo-oil column? of 45 m in Neocomian–Aptian sandstone of the Kapatimu Formation. The Pemba Trough is expected to contain Eocene age source rocks such as those encountered on Pemba Island in the Pemba-5 well. One sample from this well had a 7% TOC and a HI of 668 (Nelson 2006). Although the thickness and distribution of this Eocene source rock are not fully known, it probably sourced the small amount of oil discovered in a Miocene carbonate reef in the Sunbird-1 well, which lies in the north of the Pemba Trough (Brown 2013; Pancontinental Oil & Gas 2014). However, the significance of this oil is still not clear, as few details have been released to date. The post-Eocene sediment reaches up to 6 – 7 km thick in the centre of the trough, so there is a risk of gas (Parsons & Nilsen 2012; Parsons et al. 2013). Eocene source rock should be in the oil window on the margins of 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% (Nelson 2006). Present-day depths in the Pemba Trough indicate that these source rocks could be generating hydrocarbons.
Elsewhere, the source rocks in the Zanzibar Coastal Basin are expected to be of Jurassic age, but which are probably generating gas due to general deep burial below the Lamu Delta.
Reservoir
Good reservoir sandstones were encountered in the Pemba-5 well in the Eocene and Oligocene with intraformational shale seals expected in the Zanzibar, Pemba and Tembo troughs (Kejato 2003). The porosity of these sandstones ranges from 22 to 28% (Nelson 2006). Potential reservoirs in the deep Zanzibar Coastal Basin are not known as there are no public domain wells. However, deep-water turbidite sandstone reservoirs can be expected.
Hydrocarbon potential
There is significant potential for oil discoveries in the Pemba, 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 deep-water coastal Zanzibar Basin is considered to be more gas-prone. Deeper targets on the Zanzibar and Pemba highs can also be considered to have some oil potential. The deep-water basin is believed to be mainly unstructured at Cretaceous and Tertiary levels, and stratigraphic trapping will be required.
Lamu and southern Somalia (Juba) Basin
Introduction
The Lamu Basin straddles the onshore and offshore, and is located at the SE extension of the onshore Anza Graben, which initiated in the Upper Jurassic?–earliest Cretaceous (Fig. 22). Nine deep-water wells have been drilled in the basin. Simba-1 (west gas shows) and Pomboo-1 (dry) were both drilled on anticline traps. The reason for failure is not known. The Mbawa-1 well was drilled in 2012, which 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, encountered reservoir-quality sandstone.
Map of the Lamu and Somalia basins.
Stratigraphy
The Lamu Basin was the site of a large amount of Cretaceous–Tertiary delta deposition due to sediment flowing down the Anza Graben (Nyagah 1995). There is good evidence that large rivers linked directly between the ocean and the East African Rift, as 20 – 15 Ma whale bones have been found in the Turkana Rift area (Mead 1975), by which time a thick carbonate platform had developed in the Lamu Basin.
The shallow shelf strata contain Karoo-aged rift strata, overlain by Jurassic limestones and shales which crop out in the Mombassa region. The north–south-trending Maridadi Trough is filled by Early and Late Cretaceous and Tertiary clastics that exhibit growth thickening into the main boundary fault, indicating a multi-stage rifting event (Fig. 6). Carbonates and sandstones of Mid–Late Cretaceous age are present on the shelf and thin out at the Simba-1 well. These are separated from the Tertiary clastics by an important unconformity. Another unconformity separates the Oligocene clastics from the Miocene limestones. The deeper stratigraphy of the offshore Lamu Basin is not known, and the published wells has only drilled down to Late Cretaceous levels (Pomboo-1 and Simba-1 wells).
Structure
The deep underlying rift sequence is not clearly imaged, but Karoo and Jurassic age rifts can be expected. The large NW-trending Walu High is buried, although clearly identified on the gravity data, and 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 Embayment (north of the Walu High) and in southern Somalia (Juba Sub-basin) to produce a thin-skinned gravity fold belt, where the Pomboo-1 well is located. The detachment surface is probably a Palaeogene shale horizon (Kearns et al. 2016) (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.
Source rocks
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 Ria Kalui-1 well (located in Fig. 20). The presence of the Palaeogene detachment below the deep-water gravity fold belt suggests that the detachment weakness could be caused by overpressure.
Reservoirs
Cretaceous and Tertiary reservoir sandstones are present in the offshore area, which have been sourced from rivers flowing down the Anza Graben to the coastline. The Mbawa-1 deep-water well encountered 52 m of net pay in Upper Cretaceous sandstone reservoirs (Pancontinental Oil & Gas 2014). Good Tertiary turbidite sandstone reservoirs can be expected in the Lamu Embayment.
Hydrocarbon potential
The Lamu Basin has good reservoir potential with a large amount of clastic sediment deposited onto a delta-fed from the Anza Graben. There is a high risk of gas in the mid and outer shelf, due to the thick Tertiary fill. The deep-water gravity fold belt contains large anticlines which probably host Late Tertiary turbidite sandstone plays, but hydrocarbons will need to migrate from a deep source through the overpressured detachment.
Somalia and Puntland Coastal Basin
Introduction
The onshore and shallow-water areas of Somalia were explored in the 1950s–1970s and 31 wells (but only six offshore) were drilled. In 1960, the onshore well Coriole-1 tested 2 MMcfd (million cubic feet per day) of gas and recovered 100 bbl (barrels) of 36 – 47° API oil from Palaeogene reservoirs (Amsas Consulting Pty Ltd 2014; Soma Oil & Gas 2014); and in 1965 the Afgoy-1 well tested 6.4 – 9 MMcfd of gas from Upper Cretaceous–Paleocene reservoirs (also onshore: Amsas Consulting Pty Ltd 2014) (Fig. 22). Both of these discoveries are located in the southern part of the margin near Mogadishu. No wells have been drilled for the last 30 years because of civil war and political instability, and a Force Majeure was declared by all operators in 1989. Two of these blocks have been retained by Exxon and Shell, and in 2017 the country is planning to offer new licence blocks (Hodgson 2016)
Stratigraphy
The onshore geology is well known from 30 wells (Barnes 1976; Bosellini 1986, 1989, 1992; Piccoli et al. 1986). Karoo age strata are present along the margin and are believed to be part of a large intracratonic basin where the Triassic? Adigrat Formation basal sandstone is correlated over very large areas onshore. The overlying Jurassic sequence is carbonate-dominated with minor shales, sandstones and gypsum (the Hammanlei and Uarandab formations: Piccoli et al. 1986; St John 2016). These carbonates are widespread and extend over 1000 km inland, over the onshore Ogaden Basin into Ethiopia and northwards across into Yemen (Al Thour 1997). The shallow offshore area is also expected to have been a shallow-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.
The deep offshore Upper Jurassic–Recent sequence is expected to contain deep-water clastics, but this has not been drilled yet (Piccoli et al. 1986). Shallow-water carbonate deposition persisted through the Cretaceous and Tertiary in onshore northern Somalia, with evaporitic sabkhas developed in the Hauterivian–Valanginian. Seismic data indicate that the Early Cretaceous–Recent deep-water offshore sequence consists of mainly mudstones with some sandstone turbidites (Soma Oil & Gas 2015). The southern part of the margin is dominated by Late Cretaceous and Tertiary deltas, built across the margin with up to 4 – 5 km of clastic strata recorded in onshore wells in southern Somalia (Piccoli et al. 1986).
Structure
The margin has an abrupt transition from 25 km-thick continental crust to hyper-extended 5 – 10 km-thick crust, which is located at the present-day continental slope (Kearns et al. 2017). Outboard, the thinned crust may extend to 100 – 150 km past the shelf edge in the Obbia Basin, and exhumed mantle has been suggested (Ringenbach et al. 2017). The margin widens in Puntland to the north, with continental crust extending out to Socotra Island (Richardson et al. 1995) (Fig. 23). This is a transtensional margin during Late Triassic–Early Jurassic rifting, and a transform margin during north–south ocean spreading in the Mid-Jurassic. Several strike-slip structures have been identified on the seismic lines with unusual bed dip changes and inversion features (Fig. 23). It has been suggested that the Cretaceous Nogal Rift may extend eastwards into the northern offshore area, but there is no indicative gravity anomaly. 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 in Soma Oil & Gas 2015; Kearns et al. 2016, 2017; Stanca et al. 2016) (Fig. 23). Mid-Jurassic–Early Cretaceous strata are draped over the fault blocks, and Jurassic carbonate build-ups are probably present on fault block crests (Fig. 23c) (Soma Oil & Gas 2015).
An important phase of inversion has affected the central part of Somalia, which probably initiated in the Late Cretaceous (Fig. 23b), but continues into the Late Miocene father north (Fig. 23c). The transform margin produced a steep continental slope which has favoured the development of important gravity fold belts. The detachment levels occur at various levels and with different sliding times:
in probable Early Cretaceous shales in central Somalia in the vicinity of the Meregh-1 well, with sliding occurring approximately in the Mid-Cretaceous and limited to thrust development (Fig. 23b) (Soma Oil & Gas 2015);
in southern Somalia, a detachment also occurs at an Early Cretaceous level, with Late Cretaceous–Early Tertiary sliding (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 Miocene–Recent causing folding of the seabed (Kearns et al. 2016) (Fig. 23a).
Detachment shales were probably overpressured and generating hydrocarbons at the time of sliding (Stanca et al. 2016; Kearns et al. 2016) (Fig. 23). Bright reflectors are imaged in the Early–Mid-Cretaceous levels in the deep water, which may be source rock intervals (see the seismic line in Kearns et al. 2016).
Source rocks and maturity
No source rocks have been proven in the offshore basin so far. However, good source rocks are present in the Upper Jurassic Uarandab Formation in the Ogaden Basin with 2 – 6% TOC, which has probably sourced the moveable oil discovered in the Calub-1 and 3 wells (Ali 2006, Boote & Matchette-Downes 2009).
Reservoir
Late Cretaceous–Tertiary reservoirs are most likely to be along the southern and central portion of the margin in the Lamu Embayment and the Juba and Coriole sub-basins, where a thick Cenozoic section of 4 km has been proven by onshore wells, and discoveries have been made at Coriole-1 and Afgoi-1 (Fig. 22) (Piccoli et al. 1986).
Hydrocarbon potential
The Somalia margin is very narrow but large fold structures are present in the Juba Sub-basin (Kearns et al. 2016; Stanca et al. 2016; Soma Oil & Gas 2015) (Fig. 23). The shelfal collapse of the Late Cretaceous–Tertiary deltas in the southern area will have fed turbidite sandstone reservoirs out into the deep offshore; and stratigraphic and anticlinal traps can be expected, either formed by tectonic inversion involving the basement (e.g. the large fold on the eastern end of Fig. 23b) or by toe compression at the head of major detachment surfaces (Fig. 23a and b). Further north, in the Obbia Sub-basin, the sediment is less thick, with 3 s TWT of strata present that should place any potential Jurassic or Karoo age source rock into the oil window (Stanca et al. 2016). A late Jurassic carbonate platform has been mapped in this area (Soma Oil & Gas 2015); and Cretaceous strata are draped over the underlying large Jurassic fault blocks, and large closures are predicted in the Obbia Sub-Basin and further north (Fig. 23c).
Seychelles
Introduction
The Seychelles–Mascarene–Ritchie and Saya de Malha banks form a continental ribbon of Pan-African age (800 – 750 Ma: Tucker et al. 2001) surrounded by oceanic crust, which separated from Africa around 175 – 165 Ma and then from India around 70 – 65 Ma (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 Bank (Davison et al. 2015) (Fig. 8; see also the Supplementary material). Confidential seismic data indicate rifts with up to 6 km of sediment thickness on the Mascarene Bank at a latitude of 7° S (author's own observations). Four offshore wells have been drilled in shallow-water Seychelles, but only one of these has tested a viable structural trap and reached the intended objective horizon (PetroSeychelles 2013). Three wells (Owen-Bank-1, Seagull Shoals-1 and Reith Bank-1) had oil shows at various depths. There is a comprehensive 2D seismic coverage of most of the prospective area, and seismic data have been recently acquired across the extension of the continental ribbon far to the SE.
Stratigraphy
The wells have encountered a Triassic continental Karoo section containing thin coals with limited source rock potential, but did not reach the Lower Triassic–Permian section. The Jurassic section consists of Early Jurassic delta clastics followed by Middle Jurassic nearshore carbonates and Upper Jurassic–Early Cretaceous fine-grained clastics (PetroSeychelles 2013). The Late Cretaceous–Paleocene section is also fine-grained marine clastics, including some volcanics, which was followed by carbonate bank deposition on the plateau in the Tertiary, with deep-marine clastics further offshore. Basalts equivalent to the Deccan traps of India are present in the Seychelles, which were erupted at c. 65 Ma (Collier et al. 2008; Ganerød et al. 2011; Owen-Smith et al. 2013).
Structure
Rifting occurred in the Karoo and Jurassic times producing half-graben with up to 2 – 3 km of sedimentary fill around the Mahe Island area. A second phase of transtensional rifting occurred along the southern edge of the Seychelles Plateau in the Cretaceous from 100 Ma, with up to 6 km of sediment deposited in 10 – 15 myr (Morrison 2011; Robinson et al. 2012). Transpressional wrench faulting created positive flower structures, which are potential hydrocarbon traps. An important phase of volcanism occurred in the Late Cretaceous (84 – 78 Ma), along with the equally important Deccan age (65 Ma) volcanism.
Source rocks and maturity
The wells have not penetrated any significant oil-prone source rocks, but have never tested the deep half-graben areas where source rocks would be predicted to be better quality. Karoo source rocks were encountered only in well Reith Bank-1 with mudstones containing 2.4 – 6.7% TOC which was gas-prone. Seagull Shoals-1 and Reith Bank-1 penetrated Jurassic mudstones with up to 5.8% TOC, and coals up to 65.2% TOC (Matchette-Downes 2006a, 2010). However, these are fairly thin source horizons.
Late Jurassic–Early Cretaceous marine shales have TOCs of up to 2.1% in the Owen Bank A-1 well (Petroseychelles 2013). Oil shows have been analysed from Early Jurassic Karoo sandstone facies, with two oil families recognized of Liassic–Triassic and Upper Cretaceous–Palaeogene affinity (Matchette-Downes 2006a, 2006b, 2010).
Reservoir
Potential reservoirs are present in Karoo sandstones with porosities up to 23% (Reith Bank-1 well produced up to 1200 bbls of water/day: Petroseychelles 2013). Cretaceous sandstones and Tertiary limestones are also potential reservoirs, with porosities of up to 18% recorded in the carbonates (Petroseychelles 2013).
Hydrocarbon potential
The hydrocarbon potential of the Seychelles is difficult to assess with the limited well information available (four wells). Although good levels of TOC have been found in Karoo source rocks, the organic material is gas-prone. Many large rotated fault blocks are present throughout the Seychelles Mahe Bank, but an even larger number of blocks is predicted in the continental ribbon that extends 700 – 1000 km south of the Seychelles Islands towards Mauritius, and this area is totally unexplored. This is one of the largest unexplored stranded continental fragments in the world, and has some good hydrocarbon potential in the Karoo and Jurassic half-graben, although reservoir quality may not be so good, and this is a very remote offshore location.
Majunga and Ambilobe (or Diego) basins, Madagascar
Introduction
These are attractive basins that contain both Karoo and Early Mid-Jurassic rift fill. Thick Toarcian age salt was deposited in the offshore, but there are no indications of evaporites in the shelfal wells or onshore (Figs 24 and 25). The shallow part of the basin has been explored, with 11 wells in the onshore that have encountered gas and oil shows (Mahajamba-1 and Mariarano-1). Oil shows have been reported in shallow boreholes onshore drilled in the Ambilobe Basin (PuraVida Energy 2015). Belobaka-1 was the last well drilled in the Majunga Basin, which was by Hunt Oil in 2000 (Webster & Ensign 2007).
Geological section across the Majunga Basin, based on seismic data courtesy of ION Geophysical. The line location is shown in Figure 24.
Stratigraphy
Karoo age Sakamaena Formation strata consist of black shales and thin sandstones containing Late Permian reptile remains (Razafindrazaka et al. 1999). Seismic data indicate that the Sakamena section is also present in the centre of the onshore basin. The Sakemana Formation is unconformably overlain by Isalo sandstones. Jurassic rifting was short lived, and commenced in the Sinemurian and ended in the Bajocian in the Majunga (Besairie 1972; Papini & Benvenuti 2008). The rift fill contains 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 deposition of shallow carbonates (Besairie 1972; Papini & Benvenuti 2008). These are overlain by Bajocian–Upper Jurassic shallow-marine clastics and limestones. The Early Cretaceous sequence is dominated by marls with several lignite beds preserved, and is overlain by Cenomanian–Late Cretaceous clastics. Marine Tertiary sediments consist of dolomites, sandstones and marls in the shallow section (Razafindrazaka et al. 1999), and deep-water shales and turbiditic sandstones can be expected in deep water.
Structure
The onshore Karoo age rift faults trend NE–SW parallel to the onshore trend of the Majunga Basin (Webster & Ensign 2007). In the offshore, the deep Jurassic fault blocks are poorly imaged and the rifts are not well defined, but it is expected to be similar (NE–SW). The Toarcian age salt became mobile soon after deposition, and resulted in tall diapirs and allochthonous salt sheets in both the Ambilobe and Majunga basins (Tari et al. 2004) (Fig. 25). The allochthonous salt sheets probably extruded during the Early Cretaceous, and these have produced large potential sub-salt traps for earlier reservoirs (Tari et al. 2004) (Fig. 25). Deep-water toe-thrusts and folds are present near the seawards edge of the salt basin.
Source rocks and maturity
The Beronono organic-rich shale was deposited in the Majunga onshore area in Toarcian–Bajocian times (Besairie 1972). These source rocks contain TOC levels up to 10% with Type I/II organic material (Tari et al. 2004; Webster & Ensign 2007). There is no information on possible Cretaceous source rocks, which would significantly upgrade the deep-water area if these were present, as the Jurassic source rocks may be in the gas window in the main salt basin. However, below the allochthonous salt sheets, the source rocks will be cooled due to the high conductivity of the salt and could have remained in the oil window (Davison & Cunha 2017).
Reservoirs
Karoo age reservoir sandstones can be expected, with Triassic age Isalo sandstones.
Middle Jurassic carbonates are potential reservoirs along the shelf edge, and oolitic limestones have porosities of 12 – 22% in the Belobaka-1 well (Webster & Ensign 2007). The offshore area is expected to have Cretaceous and Tertiary deep-water turbidite sandstone reservoirs. Uplift probably occurred on Madagascar during the Jurassic rifting and during Late Cretaceous magmatism, producing erosion and consequent deposition of deep-water turbidite facies. There is no information on the reservoir sandstone quality.
Hydrocarbon potential
The Majunga Basin is a very attractive basin with good potential for oil in the shallow shelf area, which is derived from good-quality oil-prone Jurassic source rocks. The deeper-water area is probably gas-prone as the Jurassic source rocks are too deeply buried, except where the allochthonous salt sheets are present, allowing the source rocks to stay in the oil window. Stratigraphic pinch-out traps are possible in Cretaceous sandstones in the shallow shelf and onshore. There are no wells drilled in deeper than 500 m water depth, and the deep-water potential is difficult to assess. There have been no offshore wells drilled in the last 40 years, making this a potentially attractive overlooked basin.
Morondava Basin, Madagascar
Introduction
The Morondava Basin has been explored since the 1960s, and hosts the large tar sand accumulations of Bemolanga and Tsimiroro (16.5 and 3.5 billion bbls in place, respectively: Fig. 24). The oil–water 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 Webster pers. comm. 2012). The 14.8° API oil in Tsimiroro is now being used for local power generation (Madagascar Oil 2015). Approximately 58 exploration wells have been drilled throughout the Morondava Basin, with three small sub-commercial gas discoveries (Sikily-1 tested 2.65 MMscf/d (million standard cubic feet per day): Fig. 24). Seismic data are poor, and wells have not always drilled on structure or deep enough to test the better Karoo reservoirs onshore. There have been no offshore wells drilled since the 1980s.
Stratigraphy
The oldest Karoo age sedimentary rocks are found in the Morondava Basin, where glacial and lacustrine deposits of the Late Carboniferous–Late Permian age Sakoa Group reach up to 2 km in thickness (Wescott & Diggens 1997). The overlying Permian Sakamena Formation and Late Triassic Isalo Formation consist mainly of continental fluvio-lacustrine strata (Besairie 1972; Wescott & Diggens 1998). The Karoo sequence may reach up to 11 km in thickness in the southern Morondava, and the deeper parts of the Karoo stratigraphy have not been tested in this area (Boast & Nairn 1982). The Sakoa sequence consists of tillites, sandstones, shales, limestones and coals of Late Carboniferous–Early Permian age. The top of the Sakoa Formation is marked by a shallow-marine limestone of Early Permian age (Wescott & Diggens 1997). The overlying Sakamena Formation is comprised of a lower sandstone, middle shale and upper sandstone units reaching up to 4 km in thickness (Wescott & Diggens 1998).
There is believed to have been an important marine incursion in the Early Triassic, and the middle Sakamena Formation contains dark grey shales and bituminous limestones that extend over most of the basin and range from 200 to 650 m in thickness (Geiger et al. 2004). These are the source of the Bemolanga and Tsimimoro tar sands, onshore Madagascar (Webster & Ensign 2007; Ouedraogo 2012). The Isalo Formation is Triassic–earliest Jurassic? age and consists of mainly sandstones which reach up to 5 km in thickness. The top of the Isalo Formation is marked by an unconformity and is overlain by the Early Toarcian strata.
The Toarcian–Aalenian age Andafia Formation reaches up to 1500 m thick in the subsurface (Dina 1996; Boast & Nairn 1982); it contains shallow-water carbonates, sandstones and shales, with deeper-water shales present in the deeper half-graben. The strata show wedging on seismic data, indicating that they were deposited during rifting (Geiger et al. 2004). These are unconformably overlain by shallow-marine carbonates of the Bemaraha Formation of Bajocian–Bathonian age, which can reach up to 600 m thick (Ambatolahy-1 well, located in Fig. 24) (Geiger et al. 2004). The Callovian sequence consists of marginal-marine and fluvial siliclastics in the northern and central part of the basin (Mette 2004). The Oxfordian–Kimmeridgian succession consists of condensed shallow-marine to open-marine siliclastics with ferruginous oolitic beds. The overlying Early Cretaceous sequence initiates with an Aptian age conglomerate overlain by marine shales and sandstones (Mette 2004). The Tertiary sequence is dominated by limestones and dolomites and marls of Paleocene–Miocene age, and is overlain by Pliocene clastics and limestones (Stone & Leroy 2003). Major lava extrusion and sill injection took place in the Late Cretaceous (c. 88 Ma), which partially masks the deeper geology on seismic sections (Storey et al. 1995) (Fig. 26).
Seismic section across the Morondava Basin (modified from Welch & Hyden 2005). The line location is shown in Figure 24.
Structure
The initial Karoo rifting is believed to have occurred in a sinistral transtensional regime with pull-apart basins locally developed; followed by NW-trending extension to produce NE-trending fault blocks (Schandelmeier et al. 2004). The Jurassic rifting continued probably until the Toarcian, with north–south-trending rift faults active. The basin margin was uplifted and eroded in post-Jurassic times, probably during the Late Cretaceous magmatic event, causing a prominent basinwards tilt.
The Davie–Juan de Nova Ridge is located along the north–south transform margin which bounds the Morondava Basin to the west (Fig. 26). The ridge was strongly inverted during the Late Jurassic, and basement gneisses and Karoo strata have been recovered in dredge samples around the ridge (Bassias & Leclaire 1990). Smaller inversions along the Davie–Juan de Nova Ridge took place in the late Cretaceous until the late Tertiary.
Source rocks and maturity
An Early Triassic marine incursion occurred in Madagascar, and the middle Sakamena Formation contains dark grey shales and bituminous limestones which are believed to be the source of the Bemolanga and Tsimimoro tar sands. The Beronono Formation of Early–Mid-Jurassic age has been encountered with the TOC reaching 12% in the Majunga Basin. Jurassic Bemaraha deep-water carbonates may also be a potential source rock. Sakamena Formation source rocks contain 5 – 6% TOC (Webster & Ensign 2007). Triassic age Isalo shales are also present with Type III gas-prone material with 17 – 22% TOC. The Karoo and Jurassic sources are predicted to be present in the offshore. The Cretaceous section may also have potential source rocks which have been analysed in the Saronala-1 well, and these rocks may be buried deep enough to generate oil (Tari 2016).
Reservoir
Good-quality Early and Late Cretaceous sandstones reservoirs can be expected, which were derived from the uplift of Madagascar during this time, and sedimentary onlaps of this age are present along most of the margin. Large channel structures are visible on seismic data (Matchette-Downes 2006a). The Karoo age reservoir sandstones are relatively poor quality and these are not considered to be viable reservoirs in the deep offshore, except where they are less deeply buried on the Juan de Nova Ridge.
Hydrocarbon potential
There is limited potential for structural traps in the offshore basin, except along the Davie–Juan de Nova Ridge where structural inversion has occurred in the Late Jurassic, and the Karoo and Jurassic section have been uplifted by several kilometres. The Davie Ridge inversion has also produced large north–south-trending anticlinal fold closures (Fig. 26). Cretaceous pinch-out traps are present along the eastern and western margins of Morondava Basin, where turbidite deposits may have been trapped (Fig. 26). The onshore basin has good potential for Karoo and Early Jurassic structural traps, with faults juxtaposing the Beronono shales against Isalo Formation sandstone reservoirs. Most of the onshore wells have been drilled on very poor seismic data, so the lack of success does not necessarily signify that the basin has poor potential. Improved seismic imaging will open up some significant low-cost exploration opportunities onshore.
Excellent oil-prone source rocks are proven in the Karoo and the later Jurassic rift sequence onshore, and both of these sources 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). Reservoir quality in Karoo and Jurassic-aged strata is poor, so this play would only be commercial onshore. Better quality Cretaceous and Tertiary turbidite sandstones will be present offshore, and the main traps are predicted to be stratigraphic pinch-outs along the shelf margins (Fig. 26).
Conclusions
The central East African continental margin has become a focus of intense exploration activity in the last few years since the discovery of more than 200 Tcf of thermally-generated gas in Mozambique, Tanzania and Kenya. Most exploration is focused in this area, and many more gas fields will be found here as the gas fields produce a very good seismic amplitude response leading to high exploration success rates.
Farther south, around the Zambesi Delta in Mozambique to the Tugela Cone in South Africa, there is less sediment fill, and both the Jurassic and possibly Mid-Cretaceous source rocks may be in the oil window. Turonian–Albian age sources have not been tested in deeper waters along the southern part of the margin. Bright Mid-Cretaceous reflectors are present on the seismic data, seawards of the Cretaceous shelf break, suggesting that condensed organic facies may be present (fig. 10 in De Buyl & Flores 1986; Schlüter & Uenzelmann-Neben 2008). These source rocks would be produced by cold-current upwelling and preservation of organic material off the palaeo-Cretaceous shelf edge in >200 m water depth (anoxic). No wells have drilled down to this level east of the Cretaceous shelf edge, so the existence of this source rock remains hypothetical. There is less structure present in this area, but stratigraphic traps are present just above the hypothetical source level so migration should not be a problem.
The Majunga Basin is considered to be oil-prone and is highly structured by salt with a good-quality Jurassic source. Morondava has good oil-prone Karoo and Jurassic sources. The deep-water portions of the Morondava and Majunga basins have not been tested so far, but future political stability in Madagascar should encourage explorationists.
Major fold structures are present in central and southern Somalia which affect most of the Late Cretaceous and Tertiary intervals. Bright reflectors are identified in the mid-Cretaceous sequence which could be potential oil-prone source rocks. Jurassic source rocks may be present in the Obbia Basin which will be less deeply buried, and large rotated fault blocks at the Jurassic level were underfilled so large Cretaceous drape structures are present overlying possible carbonate build-ups on footwall highs.
Acknowledgements
Colin Reeves kindly provided access to much of the dyke data shown on Figure 3. Theo Faull and Eoin O’ Beirne are thanked for help with compilation of some of the map data. Matthew Taylor is thanked for compiling the Karoo correlation panel in figure 2 of the Supplementary material and for allowing this to be reproduced. New Age (African Global Energy) Ltd are thanked for permission to reproduce Figure 11. ION Geophysical are thanked for permission to show the seismic data in Figures 6 and 25. Will Parsons is thanked for permission to reproduce the cross-section in Figure 21. Phil Copestake is thanked for permission to reproduce Figure 19. Duncan Macgregor, David Boote and an anonymous reviewer provided very insightful reviews which have helped to improve this paper.
- © 2018 The Author(s)
References
Geology and hydrocarbon potential of the East African continental margin: a review
- Article
- Abstract
- Tectonic history of East Africa
- Algoa and Gamtoos rifts
- Durban Basin and Tugela Cone
- South Mozambique Basin
- Zambesi Delta and Angoche Basin
- Rovuma Basin
- Mafia and Mandawa basins
- Zanzibar Coastal Basin, and the Zanzibar, Pemba and Tembo troughs
- Lamu and southern Somalia (Juba) Basin
- Somalia and Puntland Coastal Basin
- Seychelles
- Majunga and Ambilobe (or Diego) basins, Madagascar
- Morondava Basin, Madagascar
- Conclusions
- Acknowledgements
- References
- Figures & Data
- Info & Metrics