Journal of Science Research (2014) Vol. 13: 115-132
Hydrocarbon Potential and Palaeodepositional Environment of Subsurface
Sediments of the Anambra Basin, South Eastern Nigeria
Matthew E. Nton1 and Princewill Iheanacho Ugochukwu 2
Abstract
Subsurface core samples obtained from Enugu 1325 and 1331 wells within the Anambra Basin were characterized
by standard organic geochemical methods; Rock-eval and GC-Ms; to deduce the hydrocarbon potential, source input
of the organic matter and palaeodepositional environment of the basin. The lithologies in both wells consist of coals,
shales and siltstones and belong to the Mamu Formation. The Total Organic Carbon (TOC), Soluble Organic Matter
(SOM) and Genetic Potential (GP) of the core samples ranged from 1.59 – 70.33wt%., 238.1 – 4095.2 ppm, 2.34 -
177.36 respectively. These values indicate that the source rock is moderately to fairly rich in organic matter. A cross
plot of hydrocarbon potential versus TOC, EOM versus TOC, indicated that the source rock is Type III and gas
prone. Tmax values range from 426 – 435ºC which indicate low maturation level for the source rock. The ratios of
βα/αβ C29 hopane, βα/αβ C30 hopane, and 22S/22S+22R C32 hopane ranged from 0.32 to 0.57; 0.20 to 0.59; and 0.49
to 0.56 respectively, suggesting immature organic matter. A cross plot of hydrogen index (HI) versus Tmax,
production index (PI) versus Tmax, both suggest that the source rock is immature. Further maturity parameters such
as MPI-1 (Methyl Phenanthrene Index), MDR (Methyl Dibenzothiophene Ratio), and Rm (calculated vitrinite
reflectance), revealed ranges of 0.14-0.76, 0.99-4.21, and 0.62-0.82 respectively. These indicate that the samples are
immature to marginally mature. High values were obtained from the C24 tetracyclic/C24 tricyclic terpanes and the
C19/C20 tricyclic terpane ratios, (1.54-2.25) and (0.74-1.34) respectively, which are indicative of terrigenous organic
matter. The dominance of C29 over C28 and C27 indicate higher terrigenous input. The pristane/phytane ratio of 5.08
to 8.97 indicates oxic condition of deposition for the sediments. The results show that the sediments were deposited
in oxic to suboxic environment with moderately to fairly rich organic matter of substantial terrigenous input. The
source rock has the potential to generate gas rather than oil, given sufficient maturity.
Introduction
The Anambra Basin, with a total sediment Reports of various authors are valuable in the
thickness of about 9 km, presents an exploration activities in the Anambra Basin.
economically-viable hydrocarbon deposits. It Avbovbo and Ayoola [5] reviewed
is characterized by enormous lithologic exploratory drilling results for the Anambra
heterogeneity in both lateral and vertical Basin and proposed that most parts of the
extensions derived from a range of basin probably contain gas-condensates due
paleoenvironmental settings ranging from to abnormal geothermal gradient.  Agagu and
Campanian to Recent [1]. Ekweozor [6] concluded that the Senonian
The search for commercial crude oil in shales in the Anambra syncline have good
the Anambra Basin has remained a  source of organic matter richness with maturityincreasing significantly with depth. Unomah
concern especially to oil companies and [7] evaluated the quality of organic matter in
research groups. Initial efforts were the Upper Cretaceous shales of the Lower
unrewarding and this led to the neglect of this Benue Trough as the basis for the
basin in favour of the Niger Delta, where reconstruction of the factors influencing
hydrocarbon reserves have been reportedly organic sedimentation. He deduced that the
put at 40 billion barrels of oil and about 170 organic matter and shales were deposited
trillion standard cubic feet of gas  [2- 4]. under a low rate of deposition. Specific
references to the organic richness, quality and
Matthew E.  Nton 1 and Princewill Iheanacho thermal maturity in the Mamu Formation and
Ugochukwu 2
1 Nkporo shales have been reported byDepartment of Geology, University of Ibadan, Nigeria
2 Unomah and Ekweozor [8], Akaegbobi [1]Shell Petroleum Development Company, Port and Ekweozor [9]. They reported that the
Harcourt, Nigeria
Email: ntonme@yahoo.com sediments are organic rich but of immature
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116 Journal of Science Research (2014) Vol. 13: 115-132
status. The present study, in line with current 7°30'E and falls within the Anambra Basin
understanding, tries to examine the hydro- (Fig. 1). The Nigerian sedimentary basin was
carbon potential of the Anambra Basin and formed after the break up of the South
ascertain its paleodepositional environ-ments. American and African continents in the Early
Cretaceous [10, 11]. Various lines of
Location of Study Area and Geological geomorphologic, structural, stratigraphic and
Setting paleontologic evidences have been presented
The study area is located between latitudes
– – to support a rift model [12-15].6°15'N 6°45'N and longitudes 7°15'E
Fig. 1: Geologic map of the southeastern Nigeria showing location of the study wells. Inset map of Nigeria with
arrow pointing to study area (After Whiteman 1982).
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Nton and Ugochukwu: Hydrocarbon Potential and Palaeodepositional Environment of Subsurface Sediments… 117
The stratigraphic history of the region is renamed Mamu Formation [18]. It contains a
characterised by three sedimentary phases distinctive assemblage of sandstone, sandy
during which the axis of the sedimentary shale, shale, mudstone and coal seams [18].
basin shifted [16]. More than 3000m of rocks Surface sections reveal that the Mamu
comprising those belonging to Asu River Formation comprises mainly white, fine-
Group, Eze-Aku and Awgu Formations, were grained and well-sorted sands. There are
deposited during the first phase in the frequent interbeds of carbonaceous shales
Abakaliki-Benue Trough and the Calabar with sparse arenaceous microfauna, and coal
Flank. The resulting succession from the
second sedimentary phase comprises the beds [19]. The exposed thickness of this
Nkporo Group, Mamu Formation, Ajali Formation ranges from 5-15m. According to
Sandstone, Nsukka Formation, Imo Reyment [18], the coals occuring in Enugu
Formation and Ameki Group. The third area are in five seams ranging from 30cm to
phase, which resulted  in the formation of the nearly 2m with the  middle seam, which is the
petroliferous Niger Delta, commenced in the thickest, outcropping along the Enugu
Late Eocene as a result of a major earth Escarpment for a distance of about 11 km.
movement that structurally inverted the The coals of Enugu area form only a part of
Abakaliki region, displacing the depositional the total coal resources of Nigeria [18]. On
axis further to the south of the Anambra the basis of organic geochemical and
Basin [17]. The stratigraphy of the Anambra biomarker parameters, Nton and Awarun [23]
Basin from oldest to youngest is explained described the shale and coal units of the
below. Mamu Formation as moderate to rich oil/gas
proned, immature source rock of terrestrial
Nkporo-Enugu Shale Group precursor.
These units consist of dark grey fissile, soft
shales and mudstone with occasional thin Ajali Sandstone
beds of sandy shale, sandstone and shelly This is a Maastrichtian sandy unit overlying
limestone. A shallow marine shelf environ-
ment has been predicted due to the presence the Mamu Formation. It consists of white,
of foraminifera Milliamina, plant remains, thick friable, poorly sorted cross-bedded
poorly preserved molluscs and algal spores sands with thin beds of white mudstone near
[2, 18 – 19]. Nyong [20] inferred the Nkporo the base [24]. Studies have suggested that the
Shale to have been deposited in a variety of Ajali Sandstone is a continental/fluviodeltaic
environments  ranging from shallow open sequence, characterized by a regressive phase
marine to paralic and continental settings. of a short-lived Maastrichtian transgression
North of Awgu, the Nkporo Shale shows a with sediments derived from western areas
well-developed medium to coarse-grained of Abakaliki anticlinorium and the granitic
sandstone facies referred to as Owelli basement units of Adamawa-Oban Massifs
Sandstone. The Owelli Sandstone member is [25]. The Formation, where exposed, is often
about 600 metres thick [18]. Akaegbobi and overlain by red earth, formed by weathering
Schmitt [21] evaluated the Nkporo Shales as and ferruginization of the Formation [26].
having moderate to super-rich organic matter According to Nwajide and Reijers [27], the
of types 111 and some types 11/111 of coal-bearing Mamu Formation and Ajali
immature status, sourced mainly from Sandstone accumulated during the regressive
terrestrial higher plants and deposited in phase of the Nkporo Group with associated
cyclistic suboxic and anoxic conditions. progradation. The authors characterized the
Mamu Formation Ajali Sandstones as tidal sands. Tijani and
This formation was initially named the Nton [24] reported that weathering induced
“Lower Coal Measures” [22], but later geochemical processes with resultant
formation of Fe-Mn-Al-oxyhydroxides and
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118 Journal of Science Research (2014) Vol. 13: 115-132
leaching/dissolution mobilization of metals of ironstone and thin sandstone bands, which
including contaminant trace, constitute occur especially towards the top of the unit.
potential aquifer management problems in the Ostracod and foraminifera recovered from the
Ajali Sandstone. basal limestone unit indicate a Paleocene age
for the Formation [28]. Lithology and trace
Nsukka Formation fossils of the basal sandstone unit reflect
The Nsukka Formation is a Late foreshore and shoreface or delta front
Maastrichtian unit, lying conformably on the sedimentation [29]. The Imo Formation is the
Ajali Sandstone. The unit consists of alter- up-dip lateral equivalent of part of the Akata
nating succession of sandstone, dark shales Formation in the subsurface Niger Delta [16].
and sandy shales with thin coal seams at The Formation becomes sandier towards the
various horizons. Reyment [18]  assigned the top where it consists of alternations of
name ‘Upper Coal Measures’ to this sandstone and shale [28]. The sedimentary
formation. The Formation begins with coarse succession indicate a paralic environment.
to medium-grained sandstones passing
upward into well-bedded blue clays, fine- Materials and Methods
grained sandstones, and carbonaceous shales Samples
with thin bands of limestone [17, 18]. Agagu Borehole samples from Enugu 1325 and 1331
[19] reported that the Formation has a wells, located in the Anambra basin were
thickness range of 200-300m and consists of obtained from the Nigerian Geological
alternating succession of fine-grained Survey Agency (NGSA) Kaduna, for this
sandstone/siltstones, grey-dark shale with study. The samples were logged based on
coal seams at various horizons. A strand lithological characteristics and taken into
plain/marsh environment with occassional well-labelled sample bags which were
fluvial incursions similar to that of the Mamu eventually taken to the Sedimentological
Formation was inferred for this Formation. Laboratory, Department of Geology,
University of Ibadan, for detailed description
Imo Shale and selection for subsequent laboratory
The Imo Shale overlies the Nsukka analyses. The borehole samples of the Enugu
Formation in the Anambra Basin and consists 1325 range in depths from 163 to 178 meters
of blue-grey clays and black shales with while the well 1331 samples range in depth
bands of calcareous sandstone, marl and from 218 to 234 meters (Figs. 2 & 3). A total
limestone [18]. Whiteman [2] described the of thirteen (13) samples were systematically
formation as fine textured, dark grey and selected to cover the entire depth of the core
bluish grey shale with occasional admixture samples obtained.
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Fig. 2: Litholog of Enugu well 1325.
Fig. 3: Litholog of  Enugu well 1331.
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120 Journal of Science Research (2014) Vol. 13: 115-132
Enugu Well 1325 has a sequence beginning S3 peak measures the amount of carbon
from shale overlain by siltstone, coal, shale dioxide released providing an assessment of
and siltstone sequence successively. The the oxygen content of the rock. The
shales are dark grey and fissile and the temperature at which maximum amount of
siltstone are brown to light grey in colour S2 hydrogen is generated is known as Tmax,
while the coal is blackish. In the Enugu Well which is a measure of the source rock
1331, the sequence comprises from bottom to maturity.
top coal, shale and siltstone successively. In
the middle, there is another shale, siltstone, Soluble Organic Matter (SOM)
shale and coal sequences. These sequences The Soluble Organic Matter content was done
are successively overlain by shale, siltstone, using the Soxhlet System HT2 Extraction
shale-siltstone sequence in the uppermost Unit and Methylene Chloride/Methanol
part. The shale is fissile, dark to grey while mixture (9:1) as reagents. Each weighed
the coal is dark. The siltstone ranges from pulverized sample, was taken into  cellulose
brown to light grey. In both wells, the thimbles and extracted by standard methods.
lithological sequences are cyclical. After the evaporation of the solvent, soluble
organic matter was transferred into pre-
Total Organic Carbon (TOC) weighed, labelled 20 ml glass vials and dried
Approximately 0.10 g of each pulverized under nitrogen gas at 40°C. The dried
sample was weighed and then treated with extracts were measured at room temperature
concentrated hydrochloric acid (HCl) to in parts per million (ppm). The asphaltene in
remove carbonates.The samples were left in the extracts were precipitated by the addition
hydrochloric acid for a minimum of two (2) of 10ml pentane and centrifuged. The solvent
hours. The acid was separated from the left  was separated into saturates, aromatics
sample with a filtration apparatus fitted with and NSO fractions using liquid chromato-
a glass microfiber filter. The filter was placed graphy. The saturate and aromatic hydro-
in a LECO crucible and dried at 110°C for a carbons and polar  were eluted using 20ml
minimum of one hour. After drying, the hexane, n-alkanes/dichloromethane (90:10,25
sample was analysed with a LECO 600 ml) and dichloromethane/methanol (50:50,
Carbon Analyzer. The analysis was carried 30ml) respectively.
out at the Weatherford Geochemical
Laboratory, Texas, USA. Gas Chromatography and Gas
Chromatography-Mass Spectrometry
Rock Eval Pyrolysis The analyses were carried out in a Hewlett
Based on adequate TOC, thirteen samples Packard 6890A gas chromatograph, equipped
were further characterized by Rock Eval with dual flame ionization detectors. The
pyrolysis using LECO 600 Analyzer. About chromatograph was fitted with HP-1 capillary
100mg of each pulverized samples was column (30 m × 0.32 mm I.D × 0.52 microns)
heated in an inert environment to measure the using helium as the carrier gas. The column
yield of three groups of compounds (S1, S2 temperature was programmed at 35°C to
and S3), measured at three peaks on a 300°C/min with a flow rate of 1.1 ml/min.
programme. Sample heating at 300°C for 3 Chromatographic data were acquired using an
minutes produced the S1 peak by vapourising Hp Vectra XM series 3 computer. Peak
the free hydrocarbons. The oven temperature integration and associated data processing
was increased by 25°C per minute to 600°C. were accomplished using Hp Chemstation
The S2 and S3 peaks were measured from the software. Peak identification was accompli-
pyrolytic degradation of the kerogen in the shed by matching chromatographic peaks and
sample. The S2 peak represents the amount profiles using Hp Naptha standard.
of hydrogen-rich kerogen in the rock, and the
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Nton and Ugochukwu: Hydrocarbon Potential and Palaeodepositional Environment of Subsurface Sediments… 121
The saturates and aromatic fractions Results and Discussions
recovered were analysed for their biomarker Organic Richness
composition by gas chromatography/mass The Total Organic Content of the samples
spectrometry (GC/MS) using selected ion ranged from 1.59 to 70.33wt% (Table 1). The
monitoring mode (SIM). The samples were TOC of the coal samples – V2, V3 (Enugu
mixed with a vortex mixer to agitate and were well 1331) and P2 (Enugu well 1325) are
then transferred to an auto-sampler vial and higher than what was recorded for the shale
capped. Vials were then placed on the auto- samples. Nevertheless, all the samples have
sampler to be run in an HP 6890 gas values above 0.5 wt% TOC considered as
chromatograph silica capillary column minimum for clastic source rocks to generate
(30m × 0.25mm ID, 0.25 µm film thickness) petroleum (Tissot and Welte 1984). The
coupled with HP 5973 MSD and equipped Soluble/extractable Organic Matter (SOM) of
with a flame ionization detector. The extract the samples generally exceeds 500 ppm
was rapidly injected into the gas chromato- except for samples EN 1325(P3) and EN
graph using a 10 µl syringe. Helium was used 1331(V5) with SOM values of 238.1 and
as the carrier gas with oven temperature 436.9 ppm respectively. These show that the
programmed from 80°C to 290°C. The mass samples can be classified as fair to excellent
spectrometer was operated at electron energy source rocks. Based on the quality definition
of 70 Ev, an ion source temperature of 250°C of Baker [30], the organic matter is adequate
and separation temperature of 250°C. The and it indicates good hydrocarbon potential
chromatographic data were acquired using for the studied wells. Petroleum generating
Ms Chemstation software, version G1701BA potential (GP) ranges from 2.34 to 177.36.
for Microsoft NT®.
Table 1:  TOC and Rock Eval Pyrolysis Data for the Sediments of Anambra basin
TOC=Weight percentage organic carbon in rock HI= Hydrogen Index= S2 × 100/TOC
S1,S2= mg hydrocarbons per gram of rock OI=Oxygen Index=S3 × 100/TOC
S3=mg carbon dioxide per gram of rock Tmax=°C
GP= Petroleum generic potential= S1 + S2 PI= Production Index= S1/(S1+S2)
ND=Not Done
Organic Matter Type hydrocarbon generated due to different
The organic matter type in a sedimentary organic matter type convertibilities [31]. The
rock, among other conditions, influences to a plot of hydrocarbon potential versus TOC
large extent the type and quality of (Fig. 4) indicates that the organic matter
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122 Journal of Science Research (2014) Vol. 13: 115-132
contained in the samples belong to type II/III. (Extractable Organic Matter) against TOC
Cross plot of hydrogen index (HI) versus (Total Organic Matter) shows that the organic
oxygen index (OI) (Fig. 5) corroborates that matter is gas prone (Fig. 6). Sonibare [34]
the kerogen is type II/III with majority reported that  the abundance of 1,2,5 TMN
belonging to type III. The HI in the sample (Trimethyl naphthalene) suggests a
ranged from 83 to 245. These values suggest significant land plant contribution for the
that the samples have potential to generate coals  of  Benue Trough. The  occurrence of
both oil and gas [31-32] which indicate a such biomarker in this study may also be
good source rock [33]. The plot of EOM attributed to such contribution.
Fig. 4: A plot of hydrocarbon potential S2, against TOC.
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+ Well 1325
* Well 1331
* ***
+ *** + +
+ * +
Fig. 5: A plot of hydrogen index against oxygen index for the studied wells (Modified after Van Krevelen 1961).
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Fig. 6: Cross plot of EOM vs. TOC.
Thermal Maturity immature to early peak mature (oil window).
The degree of thermal evolution of the Cross plot of hydrogen index (HI) versus
sedimentary organic matter was derived from Tmax (Fig. 7) strongly support immature
Tmax and biomarker parameters. The Tmax status for majority of the samples. Further
values  range from 426 - 435°C (av. 430oC) plot of  Production  Index (PI) against Tmax
(Table 1). This indicates that the maturity (Fig. 8) also indicate immature sediments
status of the shales and coal range from [35].
Fig. 7: Cross plot of Hydrogen Index Vs Tmax (oC).
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Nton and Ugochukwu: Hydrocarbon Potential and Palaeodepositional Environment of Subsurface Sediments… 125
Fig. 8: A plot of Production Index vs. Tmax.
The m/z 191 (hopanes) and 217 steranes biomaker  parameters such as MPI-1 (Methyl
mass chromatograms of all the samples are Phenanthrene Index), DNR-1 (Dimethyl
shown in Figures 9 and 10 respectively. All Naphthalene Ratio), TMNR (Trimethyl
the samples have similar distributions of Naphthalene ratio) and MDR (Methyl
hopanes and steranes mass chromatograms. Dibenzothiophene Ratio) derived from the
C30 hopanes are the most abundant in the m/z samples range from   0.14 to 0.76;  0.75 to
191 chromatogram. The maturity and source 2.51; 0.17 to 0.50 and 0.99 to 4.21
parameters derived from the hopane respectively. According to Radke [36] the
distributions in the shales and coals are samples are immature to marginally mature.
shown in Table 2. Calculated aromatic
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Fig. 9: m/z 191 Mass Chromatograms showing the distribution of terpanes and hopanes in the samples.
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Fig. 10: m/z 217 Mass chromatograms showing the distribution of steranes in samples P3 and V5.
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Table 2: Biomarker Parameters  Computed for the Sediments of Anambra Basin
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Some n-paraffin ratios can be used to between 0.80 and 3.91 (Table 3); this falls in
estimate the thermal maturity of sediments the immature zone. Ph/nC18 values ranged
[37]. Pristane/nC17 and phytane/nC18 can be from 0.20 to 0.57, which is below the
used to calculate thermal maturity. For the threshold value, indicating immature organic
studied wells, the Pr/nC17 values ranged matter.
Table 3: Biomarker Parameters derived from Gas Chromatograms of the Sediments
Sample ID Pr/Ph Pr/nC17 Ph/nC18 CPI OEP-1 OEP-2
EN 1331 (V2) 5.88 0.8 0.57 1.57 0.4 0.57
EN 1331 (V5) 7.26 1.98 0.33 1.83 0.43 0.56
EN 1331 (V6) 8.97 3.91 0.46 1.53 0.4 0.57
EN 1325 (P1) 5.5 1.62 0.4 1.69 0.56 0.57
EN 1325 (P3) 5.08 1.1 0.2 1.75 0.43 0.61
Carbon Preference Index (CPI) is the relative Palaeodepositional Environment
abundance of odd versus even carbon- Moldowan [42] indicated that the presence of
numbered n-paraffins and can also be used to bisnorhopane and diasterane are indicative of
estimate thermal maturity of organic matter sub-oxic conditions. The presence of such
[38] . In this study, the CPI values obtained biomarkers in this study supports suboxic
range from 1.53 to 1.83 (Table 3). Hunt [39] conditions of deposition. As reported by
has pointed out that CPI, considerably greater Peters [43], the Pristane/Phytane (Pr/Ph) ratio
than 1.0, shows contribution from terrestrial of sediments can be used to infer depositional
plants of  immature status. From this study, it environment. Pr/Ph ratios < 1 indicate anoxic
is indicative that the organic matter is of depositional environment, while values  > 1
terrestial  setting  with low maturity status. indicate oxic conditions. The values obtained
Maxwell [40] have shown that strong from the studied wells ranged from 5.08 to
odd/even bias of heavy n-alkanes is indicative 8.97, thus indicating a terrigenous-sourced
of sediment immaturity. In this study, the odd organic matter deposited in an oxidizing
numbered n-alkanes are more abundant than environment. This is further supported by the
the even numbered n-alkanes, indicating that crossplots of Pr/nC17 versus Ph/nC18
the sediments are immature. The Odd Even (Fig. 11).
Predominance (OEP) values are less than 1.0,
this is indicative of low maturity [41].
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130 Journal of Science Research (2014) Vol. 13: 115-132
Fig. 11: Plot of pristane/nC17 versus phytane/nC18 (After Moldowan et al. 1994).
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