David Thomas
Thomas & Associates
Hastings, England
The Niger delta-Benue trough region is a 1,500 km long, 50-150 km wide, intraplate northeast-southwest tectonic megastructure filled with continental and marine sediments that range in age from Lower Cretaceous to Quaternary. It is part of the mid-African rift system, whose origin is linked directly to the opening of the South Atlantic Ocean and complex interplate movement within Africa.
More precisely, the genesis of the Benue trough is connected to the opening of the equatorial domain of the South Atlantic, which was initiated in latest Jurassic-early Cretaceous.1
Northwards, the Benue trough continues into the Cretaceous rift system of Niger, Chad, the Central African Republic (Fig. 1), and eastwards into Sudan.
Tectono-stratigraphy
Four main transgressions moved northwards along the Benue trough from the newly established continental margin, and approached connections with the southern Chad Kanem basin.2
- Middle Albian: marine to junction of Yola and Gongola basins;
- Early Turonian: marine to northernmost Nigeria, or Lake Chad;
- Late Turonian: marine through Gongola basin, and possible as far as western Chad.
Compression and partial closing of the Benue trough occurred in the Cenoman- ian3 4 and again more strongly in late Santonian-early Campanian. The latter event resulted in a belt of folds striking parallel to the trough borders, with individual folds up to 50 km long, and 30 maximum flank dips (Abakaliki fold belt). A summary of the structural evolution of the Benue trough is illustrated in Fig. 2.
Published gravity data6 7 and surface grabens in Niger (Tefidet graben) demonstrate that the interior rift system extended northward, generally through the Lake Chad basin to the northern border of Niger. Gravity data suggest that the Bongor basin may have joined the Benue system in northern Nigeria. The actual connection is presumed to be obscured on gravity maps by Tertiary igneous activity, both ex- posed and apparently buried in the area.
The Doba and Birao (or Doseo) basins probably lacked a direct connection to the Benue trough, and thus were not directly influenced by the latter's marine transgressions (Fig. 3).
The oldest dated sedimentary rocks in Nigeria are in the Benue trough. They are the Lower Cretaceous (Albian) Asu River group of the Abakaliki and Anambra rift basins as well as the Bima sandstones of the middle-upper Benue region. Older sediments may well exist beneath the Niger delta basin complex, formed as the Afro-South American continents first rifted and then spread apart, but this situation would be considered much farther south, and deeply buried under the Tertiary delta.
In the Anambra basin, the Asu River group is the initial clastic fill of the southern Benue trough and consists of arkosic sandstones (Awi and Mamfe formations). Marine shales (Abakaliki shales) and limestones; and upper regressive sandstones of the Awe formation complete this unconformity bound sequence.
The Cross River group consists of shales, limestones, and sandstones of the Eze Aku and Awgu formations and the interbedded regressive sandstones of the Makurdi, Agala, Amasiri, and Agbani formations.
Following the Santonian deformational episode, the paralic Nkporo formation and the fluvio-deltaic Ajali sandstones interbedded with coal measures were laid down in the Anambra basin.
Exploration data from the Kanem basin of southwestern Chad record a predominantly paralic environment throughout the Upper Cretaceous, but information is not available for the pre-Cenomanian sequences.
The Cretaceous marine transgression that covered most of the Benue trough and into the Kanem basin is absent in the Doba and Birao basins of southern Chad. Indeed, the whole litholo-stratigraphic column in these rift basins is non-marine.
Structural styles
The structural styles found in the Benue trough can be related to:
- Graben opening stage, during latest Jurassic-Aptian time;
- Sag stage, Albian through Tertiary;
- Compressional stage, during the Cenomanian and more strongly during the Senonian.
An Aptian (?) or older arching phase is inferred from the upward coarsening of the basal clastics in certain parts of the Anambra basin. Arching is thought to be a thermal event that results from heating and expansion of crust beneath the tectonically thinned basement of the rift system. The high geothermal gradients recorded in the Anambra basin (up to 3.0 F./100 ft) also attest to this inference.
The graben opening phase resulted in normal faults with a wide range of orientations. Flexures related to the dip-slip faulting naturally parallel their controlling faults and repeat the multidirectional patterns. It would then appear reasonable to assume a complex basal facies distribution.
Late Cretaceous to Quaternary (?) deformation resulted in folding and local rejuvenation of graben faults. The folds appear compressive, and their trend pattern is mostly controlled by the Lower Cretaceous normal fault architecture. Because of this-seemingly-parallel relationship the folds are thought to reflect a graben closing event.
Strike-slip displacements along major faults are also evident, with common seismic identified flower structures, and steep upturned seismic reflectors that are truncated below less steeply dipping beds along fault boundaries.
In general, as with the majority of transpressional grabens, the rift system is asymmetric, and not very wide-50 km is an average width. Basement definition and geometry has not been clearly defined on seismic within the deepest parts of the rift system, where sedimentary fill can exceed 10,000 m.
Reservoir rocks
Shelf sandstones members of the Cretaceous aged Asu River group and shallow marine Ezu Aku formations, as well as Nkporo and Ajali (Maastrichtian) are proven petroleum reservoirs in the Anambra basin. For example, gas has been tested from sands of the Ezu Aku (Ihandiagu-1); Awgu (Ihandiagu-1, Amansiodo-1); the Nkporo (Alo-1, Igbariam-1); and Mamu (Alo-1), with minor oil in the Nkporo and Mamu (Maastrichtian sands interbedded with the coal measures).
Further north, in the Kanem and Agadem basins of Chad and Niger, minor amounts oil have been produced from the Oligocene (Kanem-1, 20 gravity) and Eocene (Sokor-1, 40 gravity), respectively.
However, the main producing interval in the Kanem basin is sandstones of Coniacian age (Sedigi-1, tested 3,200 b/d of oil, 57 MMcfd of gas, and 8,000 b/d of condensate by Conoco in 1975). Porosities are as high as 20-30%.
In the Doba basin, Turonian sandstone reservoir porosity is between 17-25%, and in Albo-Aptian reservoirs it is 4-12%.
As well as Upper Cretaceous sands (Coniacian-Maastrichtian), potential reservoirs in the Gongola and Bornu basins are Aptian-Albian deltaic sandstones, and possibly basal graben-fill non-marine sands.
Source rocks
Potential source rocks have to include shales of the Upper Cretaceous Eze Aku, Awgu, and Nkporo formations. In the Anambra basin, the problem is one of source rock over-maturation. Temperature gradients range from 2-3 F./100 ft, and the highest subsurface temperature recorded in the basin is from well Aiddo-1, with a bottomhole temperature of 284 F. (134 C.) at a depth of 3,215 m. These high temperatures probably account for the predominance of gas in the basin.8
Farther to the southwest, and where the Tertiary sequences of the Niger delta complex overlap the Cretaceous section, a much lower geothermal regime prevails. Here the prospective Cretaceous source-reservoir intervals are too deeply buried.
High present and paleo-geothermal gradients are also postulated for the Gongola basin, where lead-zinc mineralization is recorded on the southern edge of the graben, and possibly running through it. This is probably related to the Senonian igneous and folding event.9
In the Bornu basin, the geothermal regime may well be different. Oil, and gas, has been found in the Kanem and Agadem basins, along with normal or just above normal geothermal gradients. The oil window threshold is estimated at around 2,000 m (or just below the intra-Maastrichtian unconformity). In the Doba basin, the present day geothermal gradient ranges from 1.4-2.0 F./100 ft.
In the Doba and Birao basins, the best source rocks are Aptian-Albian lacustrine and deltaic shales. Dark lacustrine shales in both basins include rich sources for high pour-point oils and gas. TOC values are up to 5%.
Migration, timing
In the Doba basin, oil generation from the Albo-Aptian is most likely to have started during the Lower Cretaceous and continued through Upper Cretaceous time. The Lower Cretaceous trigger for maturation is a consequence of Albian and pre-Albian sedimentary thickness and high depositional rates during the rift stage. During the Upper Cretaceous, migrating oils would be in good stead for entrapment and re-distribution during the Senonian folding event.
Conclusions
Anambra, Gongola basins.
Large areas of the Anambra and Gongola basins have distinct petroleum exploration problems: a geologically persistent high geothermal gradient that promoted Cretaceous source rock maturation into the gas phase very early on; intrusive lead-zinc mineralization veins attributed to the Senonian igneous and folding event; and meteoric water-flushing along the periphery of the basins. From preliminary analysis, these basins have to be considered high risk for the discovery of commercial oil accumulations.
Bornu basin.
On the other hand, the petroleum potential of the Bornu basin seems favorable. This Nigerian northernmost rift basin continues into the Kanem basin of western Chad, which has proven oil accumulations in Coniacian deltaic sands. Cretaceous paleofacies is considered to be relatively continuous throughout both basins.
Paleo-geothermal history is also considered to be similar, although some igneous activity is recorded in the Bornu basin (Senonian ?).
There is a very real possibility of kerogen-rich non-marine basal Albo-Aptian basin fill lacustrine source rocks, as found in the Doba basin, could be present in the deepest sections of the Nigerian rift basins. Due to the depths involved, no well is expected to penetrate the incipient graben-fill stage sequences; however, possible oil migration from these tectono-stratigraphic units would certainly enhance the petroleum potential of cooler sections of the rift system. As opposed to interpreted thermogenic gas which seems to be prevalent in the Anambra basin.
Exploration
Twelve permits were awarded in 1993 in the southern Gongola-Yola basin region. Shell is operator of three, Chevron six, and Elf three (Fig. 4). Seismic acquisition and interpretation is in progress within the various permits. Napims (National Petroleum Investment Management Services, a subsidiary of NNPC) is active in the Bornu basin, close to the Chad border.
A group led by Esso last year signed a framework agreement with the Chad and Cameroon governments covering the main terms of pipeline transportation from Doba basin oil fields across Cameroon to the export terminal near Kribi, Cameroon (OGJ, Feb. 6, 1995, p. 38).
References
1. Maluski, H. et al., 40Ar/39 chronology, petrology and geodynamic setting of Mesozoic to early Cenozoic magmatism from the Benue trough, Nigeria, Journal of the Geological Society, London, Vol. 152, 1995, pp. 311-326.
2. Burke, K., Dessauvagie, T.F.J., and Whiteman, A.J., in Dessauvagie, T.F.J., and Whiteman, A.J., eds., African Geology, Ibadan, Nigeria, Univ. Ibadan, 1972, pp. 187-205.
3. Olade, M.A., Evolution of Nigeria's Benue trough (aulacogen)-a tectonic model, Geol. Mag., Vol. 112, 1975, pp. 575-583.
4. Nwachuku, S.O., The tectonic evolution of the southern portion of the Benue trough, Nigeria, Geol. Mag., Vol. 109, 1972, pp. 411-419.
5. Murat, R.C., Stratigraphy and paleogeography of the Cretaceous and Lower Tertiary in southern Nigeria, in Dessauvagie, T.F.J., and Whiteman, A.J., eds., African Geology, Ibadan, Nigeria, Univ. Ibadan, 1972, pp. 251-266.
6. Ajakaiye, D.E., and Burke, K., A Bouguer gravity map of Nigeria, Tectonophysics, Vol. 16, 1973, pp. 103-105.
7. Louis, P., and Rechenmann, J., Interpretation geologique de certaines anomalies gravimetriques du Tenere (Republique de Niger), Acad. Sci. C.R., Paris, Series D., Vol. 263, 1966.
8. Avbovbo, A.A., and Ayoola, O., Petroleum prospects of southern Nigeria's Anambra basin, OGJ, May 4, 1981, pp. 334-347.
9. Grant, N.K., South Atlantic, Benue trough, and Gulf of Guinea Cretaceous triple junction, GSA Bull., Vol. 82, 1971, pp. 2,295-98.
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