Shale from Asu River Group strata of the Afikpo Basin has been characterised by geochemical techniques. The aims of this study were to assess the quality of its organic matter, evaluate its thermal evolution and highlight its potential as a source rock. The determination of hydrocarbon potential of shale from the Asu River Group in Afikpo Basin, Southeastern Nigeria was carried out using some Rock-Eval pyrolysis parameters such as TOC, HI, OI, S2/S3 and S1 + S2. The shale samples were collected at Amenu and Amauro outcrop localities. The samples were examined and analyzed to determine their oil and gas potential. The HI values range from 3.95 to 47.98 mgHC/gTOC and average value of 23.17 mgHC/gTOC indicates a Type III kerogen. Tmax values ranging from 349 to 454 oC with an average of 405 oC shows that the shale samples are immature to marginally mature. The total organic carbon (TOC) (5.60 wt%) and S1 + S2 (3.05) of the shale constitutes that of excellent source rock with gas-prone kerogen indicated by Rock-Eval S2/S3 (1.71). The high oxygen index (OI) (20.84 mgCO2g-1TOC) suggest deposition in a shallow marine environment. Generated petroleum may not have reached the threshold for hydrocarbon expulsion but a review of petroleum system elements in the basin will stimulate high prospects in the Afikpo basin.

1. Oil generative potential of shale from Asu river group in the Afikpo basin, Southeast Nigeria
IJGM
Oil generative potential of shale from Asu river group in
the Afikpo basin, Southeast Nigeria
Uzoegbu MU1, Amoke AI2
1,2 Department of Geology, College of Physical and Applied Sciences, Michael Okpara University of Agriculture, Umudike,
PMB 7267, Umuahia, Abia State, Nigeria.
Shale from Asu River Group strata of the Afikpo Basin has been characterised by geochemical
techniques. The aims of this study were to assess the quality of its organic matter, evaluate its
thermal evolution and highlight its potential as a source rock. The determination of hydrocarbon
potential of shale from the Asu River Group in Afikpo Basin, Southeastern Nigeria was carried out
using some Rock-Eval pyrolysis parameters such as TOC, HI, OI, S2/S3 and S1 + S2. The shale
samples were collected at Amenu and Amauro outcrop localities. The samples were examined
and analyzed to determine their oil and gas potential. The HI values range from 3.95 to 47.98
mgHC/gTOC and average value of 23.17 mgHC/gTOC indicates a Type III kerogen. Tmax values
ranging from 349 to 454 o
C with an average of 405 o
C shows that the shale samples are immature
to marginally mature. The total organic carbon (TOC) (5.60 wt%) and S1 + S2 (3.05) of the shale
constitutes that of excellent source rock with gas-prone kerogen indicated by Rock-Eval S2/S3
(1.71). The high oxygen index (OI) (20.84 mgCO2g-1
TOC) suggest deposition in a shallow marine
environment. Generated petroleum may not have reached the threshold for hydrocarbon
expulsion but a review of petroleum system elements in the basin will stimulate high prospects
in the Afikpo basin.
Key words: Shale, Hydrogen index, Total organic carbon, Hydrocarbon potential, Asu River Group, Afikpo Basin.
INTRODUCTION
The Afikpo basin is one of the complimentary basins that
were formed after the deformation of the lower Benue
trough during the Santonian episode. It is located between
latitude 5o55ˈ to 6o00ˈN and longitude 7o51ˈ to 7o55ˈE
Southeastern Nigeria. The area has an undulating
landscape composed of mainly alternating shale and
sandstone sequence with localized clay-siltstone-
limestone intercalation.
The Sedimentary sequence of the basin comprises mainly
the Albian marine sediments, the Turonian marine
sediments and the Campanian-Recent marine sediments.
The stratigraphy of the basin consists of the Asu River
Group and the Eze-Aku Formation deposited in alternating
transgressive and regressive phases. The Asu River
Group which is the middle-upper Albian in age is the oldest
formation in the basin (Whiteman, 1982; Simpson, 1955).
White, 1982; Simpson, 1955 were of the opinion that the
Asu River Group was deposited in a moderately, deep
water environment during the Albian, with abundant
ammonites, forams, radiolarians and pollens. The
lithological units consist of shale, limestone, siltstone and
sandstone.
*Corresponding author: Mmaduabuchi Uche Uzoegbu,
Department of Geology, College of Physical and Applied
Sciences, Michael Okpara University of Agriculture,
Umudike, PMB 7267, Umuahia, Abia State. Tel.:
+2348030715958; Email: mu.uzoegbu@mouau.edu.ng
Co-author: Tel: +2348034443212; Email:
geopector@gmail.com
International Journal Geology and Mining
Vol. 3(1), pp. 081-089, June, 2017. © www.premierpublishers.org. ISSN: 0907-3409x
Research Article

2. Oil generative potential of shale from Asu river group in the Afikpo basin, Southeast Nigeria
Uzoegbu and Amoke 082
Abakiliki
Study location
Figure 1. Generalized geological map of Nigeria showing location of
studied area (Uzoegbu and Ikwuagwu, 2016a).
Three petroleum systems are present in the Cretaceous
Delta frame namely the Asu River Group, the Eze-Aku
Formation and proto-Niger Delta sequences. Also, the
Afikpo Basin has been correlated to three petroleum
systems in the Lower Congo Basin, Niger Delta and the
Anambra Basin (Odigi and Amajor, 2010).
The high total organic contents, thermal maturity and
terrigenous characteristics of the Asu River Group, Eze-
Aku Formation and proto- Niger Delta sediments, suggest
the presence of a large amount of natural gas with a small
quantity of oil generation (Odigi and Amajor, 2010).
The total organic carbon (TOC) content measures the
quantity of organic matter present in a sedimentary rock I
weight percentage (weight %). It is the most popular
screening parameter for source rock appraisal and the
basic parameter required to interpret any other
geochemical information (Bordenave et al., 1993). The
TOC is pre-requisite for sediments to generate oil or gas
(Cornford, 1998). Studies have shown that TOC content of
0.5 wt % as the threshold value for generating petroleum
from clastic source rocks (Tissot and Welte, 1984). Other
investigation on the organic carbon values for shale
indicates that a threshold value of 1.5 wt % is necessary
for the efficient hydrocarbon expulsion from source rocks
(Bordenave et al., 1993).
This study examines the hydrocarbon potential of the Asu
River Group in Afikpo Basin using organic geochemical
parameters in determining the organic matter type,
maturity, quality and quantity, petroleum potential and
depositional environment of the organic matter.
STRATIGRAPHIC SETTING
The Santonian deformational process resulted in the
fragmentation of the lower Benue trough (Fig. 1) into the
Abakiliki syncline (Kogbe, 1976). The predominantly
Albian-Cenomanian marine depositional cycles which
terminated by a phase of folding (Nwachukwu, 1972;
Olade, 1975) affected the Asu River Group in the area.
A second transgressive – regressive of deposition in the
Turonian to Santonian was again terminated by a phase of
folding and faulting in the early Santonian times. This
affected all the sediments deposited before the tectonism
and this gave rise to the Afikpo (Abakiliki) syncline (Fig. 1).
Imprint of tectonism on the sediments in the lower Benue
trough were preserved by series of joints trending NW –
SE. Typical depositional environments of a syncline are
marine, continental and transitional environments which
produced lithostratigraphic units of Asu River Group and
Eze-Aku Group (Fig. 2) etc.
The first marine transgression in Nigeria occurred during
the middle Albian. Albian sediments unnamed and
undifferentiated constitute the Asu River Group and its
equivalents (Ojoh, 1999).
Ukaegbu and Akpabio (2009) have differentiated the Asu
River Group northeast of the Afikpo Basin as consisting of
alternating shale, siltstone with occurrence of sandstone.
The maximum thickness of the Asu River Group is 1000m,
Albian in age and rich in ammonites as well as
foraminifera, radiolarian and pollens. The shales are also
characterized by species of monticeras and elobiceras
ammonites (Offodile, 1976).
The regressive phase of the first marine transgression led
to the deposition of the Cenomanian sediments. This is
found in the southeastern part of the basin around Calabar.
These beds have been assigned as Odukpani Formation
(Reyment, 1965). It was deposited under shallow water
conditions (Kogbe, 1976). The basal beds comprised of
arkosic followed by quartzose –felspathic

3. Oil generative potential of shale from Asu river group in the Afikpo basin, Southeast Nigeria
Int. J. Geol. Min. 083
AGE ANAMBRA
BASIN
AFIKPO BASIN CALABAR
FLANK
Tertiary Oligocene
Eocene
Paleocene
Ogwashi-Asaba Fm
Ameki Group
Imo Shale
Nsukka Formation
Ogwashi-asaba Fm
Ameki Group
Imo Shale
Nsukka Formation
Cretaceous
Maastricthtian
Ajali Sandstone
Mamu Shale
Ajali Sandstone
Mamu Formation
Nkporo Shale
Enugu Shale
Afikpo Sandstone
Nkporo Shale
Campanian
Nkporo Shale
Enugu Shale
Santonian
Coniacian Agwu Shale Agwu Shale
Turonian
Eze-Aku Group Eze-Aku Group
New Netim
Marl
Cenomanian
Ekenkpon
Shales
Albian
Asu-River Group Mfamosing
Limestone
Aptian
Awi Formation
Precambrian Basement Complex
Figure 2. Stratigraphic units of the lower Benue Trough (Uzoegbu and Ikwuagwu, 2016b).
and siltstone facies while shales predominate in the upper
part of the formation (Reyment, 1965).
The type locality of the Eze-Aku Group is found at the Eze-
Aku River valley in the southeast of Eze-Aku. The
formation comprised of hard grey to black shale and
siltstone. The thickness varies but may attain 100m locally.
The Eze-Aku shale represents shallow marine deposits.
The fossil contents indicate a basal Turonian age (Carter
et al., 1963; Ukaegbu and Akpabio, 2009).
MATERIALS AND METHODS
A total of 12 outcrop shale samples were obtained from the
Asu River Group at Amenu and Amauro localities in Albian
age of the Afikpo Basin. Care was taking to avoid
weathered portions of the outcrop and to obtain material
sufficient for various geochemical analyses. The samples
were hard, thickly laminated but not fissile, with texture
indicative of low permeability. In the laboratory, the
samples were reshaped using a rotating steel cutter to
eliminate surface that could be affected by alteration.
Chips were cut from the samples and dried in an oven at
105oC for 24 hours. The dried sample was pulverized in a
rotating disc mill to yield about 50 g of sample for analytical
geochemistry. The total organic carbon (TOC) and
inorganic carbon (TIC) contents were determined using
Leco CS 200 carbon analyzer by combustion of 100 mg of
sample up to 1600oC, with a thermal gradient of 160oC min-
1; the resulting CO2 was quantified by an Infrared detector.
The sample with known TOC was analyzed using a Rock-
Eval 6, yielding parameters commonly used in source rock
characterization, flame ionization detection (FID) for
hydrocarbons thermal conductivity detection (TCD) for
CO2.
RESULTS AND DISCUSSION
Table 1 shows the results of 12 bulk samples and
molecular geochemical parameters used in source rock
quality and maturity evaluation. The shale is low in
carbonate and its organic matter content within the
threshold for petroleum source rocks.

4. Oil generative potential of shale from Asu river group in the Afikpo basin, Southeast Nigeria
Uzoegbu and Amoke 084
Table 1. Bulk and molecular organic geochemical parameters for shale from the Afikpo Basin.
Organic matter quality
The TOC is a primary parameter in source rock appraisal,
with a threshold of 0.5-1 wt% at the immature stage for
potential source rocks (Tissot and Welte, 1984; Bordenave
et al., 1993; Hunt, 1996). The average value of 5.60 wt%
of the shale studied exceeds this threshold (Table 1). High
TOC of 4.45 wt% was obtained in Mamfe basin and this
value exceeds the threshold for oil generation (Eseme et
al., 2006). However, high TOC is not a sufficient condition
for oil generation. Coals usually have high TOCs that
exceed 50 wt% but do not generate oil except when rich in
liptinite, indicating the relevance of maceral composition.
In contrast, deltaic sediments may have TOCs below 1
wt% but generate commercial accumulations of petroleum
due to deposition of large volumes of sediments, as seen
in the Niger Delta. High TOC content in shales indicates
favorable conditions for preservation of organic matter
produced during deposition.
Plots of S2 vs. TOC and determining the regression
equation has been used by Langford and Blanc-Valleron
(1990) as the best method for determining the true average
HI and measuring the adsorption of hydrocarbons by the
rock matrix. They noted that HI obtained from Rock-Eval
pyrolysis of shaly source rocks, in most cases, may be less
than the true average HI of the sample due to the
hydrocarbons adsorptive capacity of the source rock
matrix (Espitalie et al., 1985) and that using the regression
equation derived from the S2 vs. TOC graph (Fig. 3)
automatically correct HI for this effect. The average HI of
the shale samples, from the S2 vs. TOC plots is very
reliable (correlation coefficient is 0.89 and has indicated a
value of 23.17 which is still 0-50mgHC/gTOC and below
(Peters, 1986), hence supporting the predominant of the
type IV with associated type III organic matter in the Asu
River Group of the Afikpo Basin. This may be related to
the redox condition, with high oxygen favoring organic
matter oxidation, also amount of organic matter type III
produced. The high oxygen index of 20.84 mgCO2 g-1TOC
suggests high contribution from terrestrial organic matter
poor in hydroxyl groups (Tissot and Welte, 1984) and that
the depositional environment was oxic.
The kerogen content of 1.10 mgHC g-1rock was described
as good, with an S2/S3 of 1.71 indicative of gas-prone
organic matter is consistent with its Tmax of 349 to 454oC,
indicative of immaturity to early maturity while the S1/TOC
of 0.29 indicates early generation of petroleum. The
hydrogen index (HI) is low compared with values slightly
below 50 mg g-1TOC for Type III - IV kerogens at the
immature stage. Type IV which is mostly inert was
obtained in this area of Afikpo Basin (Fig. 4). The oxygen
index (OI) is high, suggesting deposition in a high oxygen
environment and high terrestrial higher plant contribution
(Uzoegbu and Ikwuagwu, 2016a,b).
Rock-Eval prolysis yields parameters that are used to
describe the generation potential of a source rock by
providing information on organic matter quality, type and
maturity, with the TOC, S2 and HI as relevant parameters
(Peters, 1986). The HI of 41.20 mgHC g-1TOC of this shale
is low and results to a Type III - IV kerogens at immaturity
to early maturity stage. The gas-prone nature of this rock
rules out Type II kerogen, which usually shows S2/S3
greater than 5, while the maturity from Tmax suggest that
the current HI results from thermal evolution of a Type III
- IV kerogen, with initial HI between 600 mgHC g-1TOC and
850 mgHC g-1TOC (Lafargue et al., 1998).

5. Oil generative potential of shale from Asu river group in the Afikpo basin, Southeast Nigeria
Int. J. Geol. Min. 085
Figure 3. A diagram of S2 versus TOC of shale samples from Asu River Group with calculated
average hydrogen indices (Av. HI).
Figure 4. Showing kerogen type from modified van Krevalen diagram (After Peters, 1986).
Maturity indicators
HI vs. Tmax diagram (Fig. 5) classifies the organic matter
in the shales of the Asu River Group as type IV (inert)
kerogen (Akande et al., 2007) with some samples slightly
above the threshold (430oC) stage.
The production index (PI) is used to assess the generation
status of source rocks but is often useful when
homogeneous source rocks of different rank are
compared, in which case it is characterized as the
transformation ratio (Bordenave et al., 1993). Hunt (1996)
suggested that a PI from 0.06 to 0.96 is characteristic of
source rocks in the oil window. The value of 0.41 of this
shale is consistent with its Tmax of 405oC. This maturity is
also consistent with the fairly well fluorescing organic
matter as well as Rock Eval Tmax of 430oC, reaching the
430-435oC for low sulphur immature source rocks
containing Type III (Bordenave et al., 1993; Hunt, 1996).
The PI is not affected by expulsion (Rullkӧtter et al., 1988)
and this will not limit its use as an indicator of the organic
matter transformation because

6. Oil generative potential of shale from Asu river group in the Afikpo basin, Southeast Nigeria
Uzoegbu and Amoke 086
Figure 5. A diagram of Tmax versus HI of shale samples from Asu River Group describing
the quality of organic matter.
Figure 6. A diagram showing the characterization of organic matter SOM. vs TOC
(based on Landais and Connan in Jovancicevic et al., 2002) of samples from Afikpo
Basin indicating no migrated oil in the area.
generation may start for rocks with Type II at 0.55%Ro
(Leythaeuser et al., 1980). Rullkӧtter et al. (1988) used a
mass balance scheme to show that, at 0.68% Ro, the
transformation ratio in the Posidonia shale from northern
Germany had reached 30%. Various maturity indicators
suggest that this shale is at the immature to onset of oil
generation and its current HI of 23.17 mgHCg-1 TOC is
thought to reflect thermal evolution due to labile kerogen
from an initial HI between 600 mgHC g-1TOC and 850
mgHg-1TOC, characteristics of Type III kerogens
(Lafargue et al., 1998).
A Plot of the SOM (extract yield) against TOC (Fig. 6) as
proposed by Landis and Connan (1980) in Jovancicevic et
al. (2002) for the shale samples indicates that no migration
of oil has taken place (Fig. 6). This is supported by the
diagram of S1 + S2 vs TOC (Fig. 7) characterizing the shale
samples from the Afikpo Basin as good to excellent source
rocks with TOC and S1 + S2 above 1.0wt% and 5.0mg/g
respectively. Four samples with TOC greater than 0.6wt%
were derived from shaly carbonaceous samples. This is
also supported by the report of Beka et al. (2007) from their
investigations on shaly facies of gas prone sequences in
the Afikpo Basin
based on the values of TOC (1.09-18.24wt%) and soluble
organic matter (SOM) (190-2900ppm) which are indicative
of good to excellent and adequate source potential. Udofia
and Akaegbobi (2007) also investigated the Maastrichtian
sediments around Enugu escarpment

7. Oil generative potential of shale from Asu river group in the Afikpo basin, Southeast Nigeria
Int. J. Geol. Min. 087
Figure 7. A diagram indicating the quality of different source rocks, S1 + S2 vs
TOC of shale samples from Afikpo Basin.
of the Anambra Basin which revealed the exceeding
minimum threshold TOC value (0.65-1.82wt %) for
sediment samples and (18.35-19.12wt %) for coal
samples. Thermal maturity was confirmed by plotting the
profiles of Tmax vs TOC showing that almost all the
samples did not attain to “oil window” (430ºC) except few
samples . This is also supported by plotting the diagram of
HI vs Tmax (Fig. 5) which determine the immaturity status
of the entire sample except few samples.
HYDROCARBON POTENTIAL
In the Marginal Basins of Brazil and West Africa (Gabon,
Angola and Congo), the Cretaceous Shale’s are important
source of hydrocarbons (Mello et al., 1988a,b, 1989,1991).
Similar potential source rocks exist in the Calabar Flank,
Anambra Basin and Afikpo Basin. Recent discoveries on
the hydrocarbon generation potential of the inland basins
have generated a renewed interest for further studies.
The buildup of any prospect or of a petroleum system
requires the availability of good-quality source rocks.
Additionally, the stratigraphic position of the source rocks,
the availability of good-quality reservoir and seal
lithologies, timing of hydrocarbon generation, favourable
regional migration pathways, and trapping mechanisms
must also be considered.
The evaluation of petroleum prospect and plays in the
Anambra and Afikpo Basins has been done and classified
as having very good prospects for oil and gas (Whiteman,
1982). Haack et al. (2000), recognized a distinct
hydrocarbon system that falls within the Anambra Basin,
which features type II and type III oil prone kerogen,
derived from Agwu and Imo formations. The geochemical
analysis conducted shows that Eze-Aku shale, Agwu,
Nkporo, Mamu and Enugu Shales are high in organic
richness and ranges from immature to marginally mature
source rocks while the Asu-River shale has condensate
and dry gas.
CONCLUSION
The buildup of any prospect or of a petroleum system
requires the availability of good-quality source rocks.
Additionally, the stratigraphic position of the source rocks,
the availability of good-quality reservoir and seal
lithologies, timing of hydrocarbon generation, favourable
regional migration pathways, and trapping mechanisms
must also be considered. Shale from the Asu River Group
in the Afikpo basin has been characterized for its source
potential using bulk and molecular geochemistry. The HI
values range from 3.95 to 47.98 mgHC/gTOC with a mean
value of 23.17 mgHC/gTOC indicates a Type III kerogen.
Tmax values ranging from 349 to 454 oC with an average
of 405 oC consistently indicates an immature to early
mature source. The shale is a good quality source rock,
with gas-prone kerogen. Generated petroleum may not
have reached the threshold for hydrocarbon expulsion but
a review of petroleum system elements in the basin will
stimulate high prospects in the Afikpo basin.
ACKNOWLEDGEMENTS
Gratitude is expressed to all the Staff in the Department of
Geology, Michael Okpara University of Agriculture,
Umudike on their advice towards the success of this work.
Trican Geological Solutions, Alberta, Canada is gratefully
acknowledged for the analyses of these samples.

8. Oil generative potential of shale from Asu river group in the Afikpo basin, Southeast Nigeria
Uzoegbu and Amoke 088
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Accepted 12 March, 2017.
Citation: Uzoegbu MU, Amoke AI (2017). Oil generative
potential of shale from Asu river group in the Afikpo basin,
Southeast Nigeria. International Journal Geology and
Mining 2(2): 064-070.
Copyright: © 2017 Uzoegbu MU, Amoke. This is an open-
access article distributed under the terms of the Creative
Commons Attribution License, which permits unrestricted
use, distribution, and reproduction in any medium,
provided the original author and source are cited.