CHAPTER ONE

1.0 INTRODUCTION

The Anambra Basin is one of the major sedimentary basins of Nigeria. It comprises

of a nearly triangular shaped embayment covering about 30,00sqKm and having a

total sedimentary thickness of about 9km. The stratigraphic history of the basin is

characterized by the second sedimentary phase (Campanian – Eocene) in south-

eastern depositional cycle (Short and Stӓuble, 1967; Murat, 1972; Obi et al., 2001).

This sedimentary phase was initiated by the Santonian folding and uplift of the

Abakaliki anticlinorium along the NE-SW axis, (fig. 1.1) and the consequent

dislocation of the depocenter into the Anambra Basin on the northwest and the

Afikpo syncline on the southeast (Short and Stӓuble, 1967; Murat, 1972). The

resulting succession comprises the Nkporo group, Mamu formation, Ajali

sandstone, Nsukka formation, Imo formation and Ameki group (fig 1.2).

Early hydrocarbon exploration of the Anambra Basin is owed to the abundant

Maastrichtian coal deposits. Several efforts to explore its petroleum potentials

were unrewarding, resulting to neglect from both research groups and oil

companies. Nevertheless, with the increasing quest for petroleum development of

Nigeria inland basins, the advent of improved exploration techniques, integrated

basin analytical methods, and ultimately the global energy demand, petroleum

exploration and prospecting activities within the Anambra Basin has taken a new

dimension. This research provides required information towards optimization of

petroleum exploration and exploitation of the Anambra Basin.

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1.1 LOCATION AND ACCESSIBILITY

The Anambra Basin is located in the southern part of the regionally extensive

northeast-southwest trending Benue Trough (fig. 1.3). It lies within longitude

7000’E to 8000’E and latitude 6000’N to 7000’N. On the west, it is bounded by the

Precambrian basement complex rocks of western Nigeria and on the east by the

Abakaliki anticlinorium. The boundaries to the north and south are not very well-

defined (Uma and Onuoha, 1997).

Good road networks traverse virtually all the outcrops within the Anambra basin.

The Enugu – Onitsha expressway cuts through the outcrops of Campanian,

Maastrichtian and Eocene deposits at Iva valley, Agu-Abor and Umunya

respectively, enabling detailed descriptive study of the outcrops. Also along the

Okigwe – Umuahia districts, Campanian and Maastrichtian deposits are accessed

by road cuts.

1.2 RELIEF AND DRAINAGE

Anambra Basin is characterized generally by hilly and undulating relief. The major

landforms include the highlands of Awgu, Udi, Nsukka, Ngwo, Umunya, Obosi and

Nsugbe. All the formations generally trend north to south, and various prominent

landforms and related features have been carved out of them (Ofomata, 1975).

The Nsukka – Okigwe cuesta is one of the prominent landforms which, in Enugu

area, is made up of two distinctive features of Enugu and Awgu escarpments, and

the Udi – Nsukka plateau (Ofomata, 1975).

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Figure 1.1 Tectonic map of Southern Nigeria (adapted from Murat 1970)

According to Ofomata (1978), the scarp face of the cuesta is formed by resistant

sandstone of lower coal measures, while the gentler slopes and the crest are

formed by the less resistant Ajali formation. Ofomata also explained out that the

plateau is very extensive, 48km wide in Nsukka area and 16km wide in Udi and

Awgu area. The plateau is also characterized by low density drainage and wide,

flat bottom dry valleys, thought to be former normal river valleys that later got

dried up by infiltration into the Ajali formation. Alternatively, dry valleys in the

Enugu escarpment may be caused by progressive migration of the water table

caused by gullying and ravination (Ofomata, 1978).

The present Anambra state falls into two main landform regions: a high region of

moderate elevation, which covers much of the state south of the Anambra river,

and low plains to the west, north and east of the highlands. The highland region is

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highest in the south-east (about 410m above sea level) and gradually decreases in

height (about 33m) in the north-west on the banks of the Anambra river and the

Niger (AAPG Bulletin, 2004).

At Onitsha and Otuocha, the cuesta provides well drained low land, very close to

the river, thereby enabling settlements to extend to the banks of the river (AAPG

Bulletin, 2004).

The drainage pattern of Anambra Basin is dendritic. It is drained mainly by the

Anambra river and its main tributaries, the Mamu and Adada river. The Anambra

river rises on the Gala plateau near Ankpa in Kogi state and flows through the

northern low plain where it meanders heavily, developing oxbow lakes and

abandoned meander channels. Its largest left bank tributary is the Mamu river,

which drains extensive areas of Uzo-Uwani in the northwest and Awgu in

southwest (fig. 1.4). The higher cuesta seperates the numerous east-flowing

tributaries of the Mamu river from the west flowing rivers (the Idemili, the Nkisi

etc.) which drains the dip slope of the cuesta.

1.3 CLIMATE AND VEGETATION

Anambra Basin lies within the equatorial monsoonal climatic belts of Nigeria

typified by rainy and dry seasons. Its climate is hot and humid, with maximum

temperature of 340C and minimum of 180C – 210C towards the end of the rains.

The rainy season lasts for a period of about eight months (March to October) with 4

mean annual rainfall of 152.4cm to 203.2cm in the Enugu area to 101.6cm to

228.6cm in Idah area (Offodile, ). Dry season is relatively short and lasts for a

period of about four months (November to February).

Fig. 1.3 Location of the Anambra Basin (Adapted from Onyekuru and Iwuagwu, 2010).

The natural vegetation varies from tropical dry forest in the north, comprising of

tall trees with thick undergrowth and numerous climbers, to tropical rainforest in

the southern part, comprising of large overgrowth with shrubs, stunted trees and

tall elephant grasses.

1.4 REVIEW OF PREVIOUS WORKS

The deposition of organic sediments in Benue Trough under paleoanoxia was first

reported by Murat (1972) and was later examined in greater details by Petters

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(1982), Petters and Ekweozor (1982), Ehinola (1995) and Akaegbobi and Schmitt

(1998).

Several workers including Simpson (1954) and Reyment (1965) described the

Nkporo shale group as dark grey, very fissile shale and mudstone with occasional

thin sandyshale interbeds, fine-grained sandstone and marl with coatings of

sulphur and numerous white specks of Bolivinia explicate. Murat (1972) also

agreed with this description of Nkporo shale group.

Petters and Ekweozor (1982) suggested that the dark grey Nkporo shale was

deposited in anoxia condition resulting from bottom water stagnation due to

density stratification caused by high input of terrrigenous organic matter and poor

circulation. While evaluating the geochemical characters of the Nkporo shale,

Tebo (2000) also reported that the shale were probably deposited under a strong

anoxic water condition.

According to Agagu and Ekweozor (1982), there is a presence of abundant organic-

rich shales as source rocks with organic carbon ranging from 0.22 to 4.16% within

the Anambra Basin. On investigation of source rock potential of various

formations in the Benue Trough and Anambra Basin, Obaje et. al. (1999) proposed

that the Nkporo/Enugu shale is the source rock for the petroleum system in the

Anambra Basin, having TOC values ranging from 1.1 – 4.2wt% and vitrinite

reflectance values ranging from 0.44 – 0.60R0%. When given sufficient maturity,

they also reported that the Mamu formation is capable of expelling hydrocarbon.

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Ekweozor and Gormly (1983) described the Nkporo shale as an example of a

marine source rock composing of type II/III kerogens with low but consistent

contribution from marine organic matter.

The Campanian Nkporo shale was observed by Akaegbobi and Schmitt (1998) to be

a good example of mixed terrestrially marine source rock within the Anambra

Basin. Unomah and Ekweozor (1993) proposed that the shale in the Anambra

Basin and Afikpo syncline contain mainly terrestrially derived organic matter and

essentially gas prone. They also stated that the outcrop and near surface sections

of Nkporo shale are immature while the lower section is overcooked. Ojo, Ajibola

and Akande (2009) also concluded that the terrestrially derived type III organic

matter with potentials of generating gas is prevalent in the Campanian –

Maastrichtian formation. This is indicated by low hydrogen index (HI) values and

predominance of vitrinite. They further reported that the Total Organic Carbon

(TOC) values for the source rock interval of Campanian – Maastrichtian Enugu

formation vary from 1.29 to 4.42wt% and Soluble Organic Matter (SOM) content

ranges from 578 to 1931ppm, suggesting fair to good source rocks.

According to Unomah and Ekweozor (1993), the organofacies of Nkporo shale are

provincial with the Calabar flank having highest oil potential whereas those in the

Anambra Basin and Afikpo syncline are gas prone. After carrying out a

comprehensive study on the geology and petroleum potential of the Senonian to

Maastrichtian sediments in the Anambra Basin, Agagu (1978) recorded that the

sediments are organically rich but immature. Unomah and Ekweozor (1993),

Akaegbobi and Schmitt (1998), Obaje et. al. (1999) and Ajayi (2006), after a specific

study on the organic richness, quality and thermal maturity of the Mamu

formation and Nkporo shales, also reported that the sediments are organic-rich

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but of immature status. Agagu and Ekweozor (1982) worked on the source rock

characteristics of the Senonian shales in the Anambra syncline and concluded that

the shale have good organic matter richness with maturity increasing significantly

with depth.

The Maastrichtian – Paleocene sediments in the southern and mainly in the

southwestern sector of the Anambra Basin, according to Ekine and Onuoha (2010),

should be the major sedimentary strata with liquid hydrocarbon potentials,

whereas the lower Cretaceous and particularly the Santonian sediments exhibit

the highest potentials for gaseous hydrocarbons. Akaegbobi and Udofia (2009)

suggested that hydrocarbons are probably being generated in the Anambra Basin

which may not have been expelled in large quantities. Onyekuru and Iwuagwu

(2010) suspected the profuse seepage of fluids from the lowermost section of

Nkporo shale at the outcrop along Leru section to be hydrocarbon.

Ekine and Onuoha (2010) attributed the absence of accumulated liquid

hydrocarbon in the north-central parts of the Anambra Basin to be lack of

adequate stratigraphic and structural traps relative to time of hydrocarbon

maturation. Onyekuru and Iwuagwu (2010) identified the alternation of

Highstand System Tract (HST) and Trangressive System Tracts (TST) sands and

shales respectively in an outcrop of Nkporo shales and Mamu formation along Leru

– Okigwe axis of the Anambra Basin. This alternation provides a union of reservoir

and seal rocks which are essential for hydrocarbon accumulation and stratigraphic

trapping.

Schmitt (1998), on evaluation of the economic potentials of the Mamu formation

and Nkporo/Enugu geological units reported that the Nkporo/Enugu shales

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presented better evidence of organic matter preservation and petroleum

potential. He also identified only one petroleum system (upper Cretaceous –

lower Paleocene petroleum system) which consists of types II and III/II gas/oil

prone kerogens.

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