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Research ArticleUse of Geochemical Fossils as Indicators of
Thermal Maturation:An Example from the Anambra Basin, Southeastern
Nigeria
Olumuyiwa Adedotun Odundun
Department of Earth Sciences, Adekunle Ajasin University,
Akungba Akoko, Ondo State, Nigeria
Correspondence should be addressed to Olumuyiwa Adedotun
Odundun; [email protected]
Received 28 April 2014; Revised 31 August 2014; Accepted 1
September 2014
Academic Editor: Franco Tassi
Copyright © 2015 Olumuyiwa Adedotun Odundun. This is an open
access article distributed under the Creative CommonsAttribution
License, which permits unrestricted use, distribution, and
reproduction in any medium, provided the original work isproperly
cited.
Organic geochemical studies and fossil molecules distribution
results have been employed in characterizing subsurface
sedimentsfrom some sections of Anambra Basin,
southeasternNigeria.The total organic carbon (TOC) and soluble
organicmatter (SOM) arein the range of 1.61 to 69.51 wt% and 250.1
to 4095.2 ppm, respectively, implying that the source rocks are
moderately to fairly rich inorganic matter. Based on data of the
paper, the organic matter is interpreted as Type III (gas prone)
with little oil. The geochemicalfossils and chemical compositions
suggest immature to marginally mature status for the sediments,
with methyl phenanthreneindex (MPI-1) and methyl dibenzothiopene
ratio (MDR) showing ranges of 0.14–0.76 and 0.99–4.21,
respectively. The abundanceof 1,2,5-TMN (Trimethyl naphthalene) in
the sediments suggests a significant land plant contribution to the
organic matter. Thepristane/phytane ratio values of 7.2–8.9 also
point to terrestrial organic input under oxic conditions. However,
the presence of C
27
to C29steranes and diasteranes indicates mixed sources—marine
and terrigenous—with prospects to generate both oil and gas.
1. Introduction
The Anambra Basin is a late Cretaceous–Paleocene deltacomplex
located in the southern Benue Trough (Figure 1).It is characterized
by enormous lithologic heterogeneity inboth lateral and vertical
extension, derived from a rangeof paleoenvironmental settings
ranging from Campanian toRecent [1].
The search for commercial crude oil in the AnambraBasin has
remained a real source of concern especiallyto oil companies and
research groups. Initial efforts wereunrewarding and this led to
the neglect of this basin in favourof the Niger Delta, where
hydrocarbon reserves have beenreportedly put at 40 billion barrels
of oil and about 170 trillionstandard cubic feet of gas [2–4].
The Nigerian sedimentary basin was formed after thebreakup of
the South American and African continents inthe Early Cretaceous
[5, 6]. Various lines of geomorpho-logic, structural,
stratigraphic, and paleontological evidenceshave been presented to
support a rift model [7–10]. Thestratigraphic history of the region
is characterised by three
sedimentary phases [11], during which the axis of the
sedi-mentary basin shifted.More than 3000mof rocks comprisingthose
belonging to Asu River Group and the Eze-Aku andAwgu Formationswere
deposited during the first phase in theAbakaliki-Benue Basin and
the Calabar Flank. The resultingsuccession from the second
sedimentary phase comprises theNkporo Group, Mamu Formation Ajali
Sandstone, NsukkaFormation, Imo Formation, and Ameki Group. The
thirdphase, credited for the formation of the petroliferous
NigerDelta, commenced in the Late Eocene as a result of a
majorearth movement that structurally inverted the Abakalikiregion,
displacing the depositional axis further to the southof the Anambra
basin [12].
Reports of various authors are valuable in the
explorationactivities in the Anambra Basin. Avbovbo and Ayoola
[13]reviewed exploratory drilling result for the Anambra Basinand
proposed that most parts of the basin probably con-tain
gas-condensates due to abnormal geothermal gradient.Agagu and
Ekweozor [14] concluded that the senonian shalesin the Anambra
syncline have good organic matter richnesswith maturity increasing
significantly with depth. Unomah
Hindawi Publishing CorporationJournal of GeochemistryVolume
2015, Article ID 809780, 11
pageshttp://dx.doi.org/10.1155/2015/809780
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2 Journal of Geochemistry
[15] evaluated the quality of organic matter in the
UpperCretaceous shales of the Lower Benue Trough as the basisfor
the reconstruction of the factors influencing organicsedimentation.
He deduced that the organic matter andshales were deposited under a
low rate of deposition. Specificreferences to the organic richness,
quality, and thermalmaturity in the Mamu Formation and Nkporo
shales havebeen reported by Unomah and Ekweozor [16], Akaegbobi[1],
and Ekweozor [17]. They reported that the sedimentsare organic rich
but of immature status. Iheanacho [18]investigated aspects of
hydrocarbon source potential of theorganic rich shales belonging to
some parts of the Anambrabasin. He indicated the source rocks as
shales and coals,which present good prospects in terms of economic
viabilityas typified by the quantity and quality of organic matter
theycontain.
This study thereby aims at producing an extensive molec-ular
fossil record of some parts of Enugu Shale and coalmeasures of the
Mamu Formation.
2. Location of Study Area and Geology
The study area is located between latitude 6∘15N–6∘45Nand
longitude 7∘15E–7∘30E and falls within the Anam-bra Basin (Figure
1). The stratigraphic succession of theAnambra Basin, at the second
sedimentary phase, comprisesthe Campanian-Maastrichtian
Enugu/Nkporo/Owelli For-mations (which are lateral equivalents).
This is succeeded bytheMaastrichtianMamu Formation andAjali
Sandstone.Thesequence is capped by the Tertiary Nsukka Formation
andImo Shale. These are discussed below.
2.1. Nkporo-Enugu Shale Group. These units consist of darkgrey
fissile, soft shales, and mudstone with occasional thinbeds of
sandy shale, sandstone, and shelly limestone. Ashallow marine shelf
environment has been predicted dueto the presence of foraminifera
Milliamina, plant remains,poorly preservedmolluscs, and algal
spores [2, 19, 20]. Nyong[21] inferred the Nkporo Shale to have
been deposited in avariety of environments including shallow open
marine toparalic and continental settings.
North of Awgu, theNkporo Shale shows a well-developedmedium to
coarse-grained sandstone facies referred to asOwelli
Sandstone.TheOwelli Sandstonemember is about 600metres thick
[19].
2.2. Mamu Formation. This formation is also known as“Lower Coal
Measures.” It contains a distinctive assem-blage of sandstone,
sandy shale, shale, mudstone, and coalseams [19]. Surface sections
reveal that the Mamu Forma-tion comprises mainly white,
fine-grained and well-sortedsands. There are frequent interbeds of
carbonaceous shaleswith sparse arenaceous microfauna and coal beds
[20]. Theexposed thickness of this Formation ranges from 5 to
15m.According to Reyment [19], the coals occurring in Enuguarea are
in five seams ranging from 30 cm to nearly 2m.The middle seam—the
thickest—outcrops along the Enugu
Geologic boundary approximateGeologic boundary
inferredAnticlinal axis
Synclinal axis
Imsh
Nsh
LCM Lower coal measures
Ansh Shale and limestone (Awgu Fm.)
Ess Sandstone (Eze-Aku group)
Esh Black shale, siltstone and, sandstone (Eze-Aku group)
Enugu 1325 wellEnugu 1331 wellRiversRailway
N7∘00
E 7∘30E 8∘00
E7∘00
N
6∘30
N
6∘00
N
Shale and mudstone (Nkporo formation)
Clay and shale with limestone intercalations—Imo group
Figure 1: Geologic map of the Anambra Basin showing the
studyarea.
Escarpment for 11 km. The coals of Enugu area form only apart of
the total coal resources of Nigeria [19].
2.3. Ajali Sandstone. This is a Maastrichtian sandy unit
over-lying theMamu Formation. It consists of white, thick,
friable,poorly sorted cross-bedded sands with thin beds of
whitemudstone near the base [22]. Studies have suggested thatthe
Ajali Sandstone is a continental/fluviodeltaic
sequencecharacterised by a regressive phase of a short-lived
Maas-trichtian transgression with sediments derived
fromWesterlyareas of Abakaliki anticlinorium and the granitic
basementunits of Adamawa-ObanMassifs [23]. The Formation,
whereexposed, is often overlain by red earth, formed by
weatheringand ferruginization of the Formation [24]. According
toNwajide and Reijers [25], the coal-bearingMamu Formation,and
Ajali Sandstone accumulated during the regressive phaseof the
Nkporo Group with associated progradation. Theauthors characterised
the Ajali Sandstones as tidal sands.
2.4. Nsukka Formation. The Nsukka Formation is a
LateMaastrichtian unit, lying conformably on theAjali
Sandstone.
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Journal of Geochemistry 3
The unit consists of alternating succession of sandstone,
darkshales, and sandy shales with thin coal seams at
varioushorizons, hence termed the “Upper Coal Measures”
[22].TheFormation begins with coarse tomedium-grained
sandstonespassing upward into well-bedded blue clays,
fine-grainedsandstones, and carbonaceous shales with thin bands of
lime-stone [12, 19]. Agagu et al. [20] reported that the
Formationhas a thickness range of 200–300mand consists of
alternatingsuccession of fine-grained sandstone/siltstones and
grey-dark shale with coal seams at various horizons. A
strandplain/marsh environment with occasional fluvial
incursionssimilar to that of the Mamu Formation was inferred for
thisFormation.
2.5. Imo Shale. The Imo Shale overlies the Nsukka Formationin
the Anambra Basin and consists of blue-grey clays andblack shales
with bands of calcareous sandstone, marl, andlimestone [19].
Ostracod and foraminifera recovered fromthe basal limestone unit
indicate a Paleocene age for theFormation [26]. Lithology and trace
fossils of the basalsandstone unit reflect foreshore and shoreface
or delta frontsedimentation [27]. The Imo Formation is the lateral
equiv-alent of the Akata Formation in the subsurface Niger
Delta[11]. The Formation becomes sandier towards the top whereit
consists of alternations of sandstone and shale [26].Nwajideand
Reijers [25] interpreted the Imo Shale to reflect productof
shallow-marine shelf in which foreshore and shoreface
areoccasionally preserved.
3. Weathering and Contaminationof Rock Samples
Borehole samples are preferred because they provide a
con-tinuity of vertical sections over tens or hundreds of
metres.Even some of the best natural outcrops or exposures do
notprovide this coverage, because beds are weathered away [28].The
weathering of outcrop samples and contamination couldgive rise to
false and pessimistic indications of hydrocarbonpotential. Although
well samples can be contaminated bydrilling fluid additives (diesel
contamination, e.g., can berecognised from gas chromatography by
the high concentra-tions of 𝑛-alkanes up to C
20), steranes and triterpenes should
be unaffected. Borehole samples were therefore used for
thisstudy.
4. Analytical Methods
Borehole samples from Enugu 1325 and 1331 wells wereobtained
from Nigerian Geological Survey Agency (NGSA),Kaduna and used in
this study. The borehole samples, Enugu1325, range in depths from
165 to 177m while Well 1331 rangein depths from 219 to 233m. Enugu
well 1325 has a sequencebeginning from shale, overlain by
siltstone, coal, shale, andsiltstone successively (Figure 2). The
shales are dark grey andfissile; the siltstone is brown to light
grey while the coal isblackish. Enugu well 1331 has a bottom to top
sequence whichbegins from coal, shale, and siltstone successively.
In themiddle section is a siltstone-shale sequence which is
overlain
Siltstone, light grey to brown
Shale, dark, grey, fissile
Shale, dark grey, fissile
Shale, dark grey, fissile Shale, dark grey, fissile
Coal, blackish
Sam
ple I
D
num
ber
Lith
olog
y
Thic
knes
s (m
)
P1
P2
P3
P4P5
Coal Shale Siltstone
Lithologic description
−165
−167
−169
−171
−173
−175
−177
Scale: 1.6 cm to 1m
Figure 2: Lithostratigraphic log of Enugu 1325 well.
by another coal, shale, and siltstone succession (Figure
3).Thirteen (13) representative core samples made up of four
(4)coal samples and nine (9) shale samples were subjected toorganic
geochemical analysis.
4.1. Total Organic Carbon (TOC) Determination. Approx-imately
0.10 g of each pulverized sample was accuratelyweighed and then
treated with concentrated hydrochloricacid (HCl) to remove
carbonates. The samples were left inhydrochloric acid for a minimum
of two (2) hours. The acidwas separated from the sample with a
filtration apparatusfitted with a glass microfiber filter. The
filter was placed ina LECO crucible and dried at 110∘C for a
minimum of onehour. After drying, the sample was analysed with a
LECO600 Carbon Analyzer. The analysis was carried out at
theWeatherford Geochemical Laboratory, Texas, USA.
4.2. Rock Eval Pyrolysis. The thirteen samples were
furthercharacterised by rock eval pyrolysis to identify the typeand
maturity of organic matter and petroleum potentialin the studied
area. Rock-Eval II Pyroanalyzer was usedfor this analysis.
Pulverised samples were heated in aninert environment to measure
the yield of three groups ofcompounds (S
1, S2, and S
3), measured as three peaks on a
program. Sample heating at 300∘C for 3 minutes producedthe
S1peak by vapourising the free hydrocarbons. High
S1values indicate either large amounts of kerogen derived
bitumen or the presence of migrated hydrocarbons.The
oventemperature was increased by 25∘C per minute to 600∘C.
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4 Journal of Geochemistry
Lithologic description
Shale, dark, grey, fissile
Coal, blackish Coal, blackish
Siltstone, brown to light grey
Shale, dark, grey, fissile
Shale, dark, grey, fissile
Siltstone, brown to light grey
Shale, dark grey, fissile Shale, dark grey, fissile Coal,
blackish
Sam
ple I
D
num
ber
Lith
olog
y
Thic
knes
s (m
)
V4
V3V2V1
V5
V6
V8V7
−219
−221
−223
−225
−227
−229
−231
−233 Scale: 1.4 cm to 5m
Coal Shale Siltstone
Figure 3: Lithostratigraphic log of Enugu 1331 well.
The S2and S
3peaks were measured from the pyrolytic
degradation of the kerogen in the sample. The S2peak is
proportional to the amount of hydrogen-rich kerogen inthe rock,
and the S
3peak measures the carbon dioxide
released providing an assessment of the oxygen content of
therock. The temperature at which S
2peak reaches maximum—
𝑇max—is a measure of the source rock maturity.
4.3. Determination of Soluble Organic Matter (SOM). Thesoluble
organic matter content of both shale and coal sampleswas carried
out to estimate the free hydrogen content ofthe samples. This was
done using the Soxhlet System HT2Extraction Unit and Methylene
Chloride/Methanol mixture(9 : 1) as the solvent. Each pulverised
sample, after beenweighed, was placed into labelled cellulose
thimbles andplugged with glass wool and adapter. For shale sample,
20 gwas taken while 2–4 g was taken for coal. The
thimble,extraction cups and 100mls of methylene chloride
:methylsolution were placed inside a tecator system. The solvent
wasallowed to boil, and then the thimbles were lowered into
thesolvent and left for an hour.The stop corkwas closed for
fasterevaporation. After evaporation, soluble matter were
turnedinto preweighed, labeled 20mL glass vials, and dried
withnitrogen at 40∘C. The dried extract was weighed at
roomtemperature.
The soluble organic matter was then calculated; thus,
SOM (ppm) =Weight of extract (g)Weight of sample
× 106. (1)
The extraction was carried out at Exxon Mobil
GeochemicalLaboratory, Que Iboe Terminal (QIT), Eket.
4.4. Gas Chromatography of Whole Oil. The analyses werecarried
out in a Hewlett Packard 6890A gas chromatograph,equipped with dual
flame ionization detectors. The chro-matograph was fitted with HP-1
capillary column (30m ×0.32mm I.D × 0.52 microns) using helium as
the carriergas. The column temperature was programmed at 35∘C
to300∘C/min with a flow rate of 1.1mls/min. The bitumenextract
(SOM) was diluted with drops of carbon disulphidewhile agitating
until sample is dissolved. A little volume wasplaced in a labeled
auto-sampler vial which was transferredto the autosampler tray for
the analysis to run. 1.0𝜇L of thediluted extract was rapidly
injected to the gas chromatographin split mode, using a graduated
Hp 10𝜇L injection syringe.This analysis was carried out at the
ExxonMobilGeochemicalLaboratory (QIT), Eket, Nigeria.
4.5. Gas Chromatography Mass Spectrometry. For GC/MSto be
carried out on an extract (soluble organic matter),it must be
separated into its fractions, that is, saturate,aromatic,
asphaltene, and resin. The gravimetric columnchromatography method
was applied in the separation ofextract into saturate, aromatic,
resin, and asphaltene fractions(SARA). It is modified from the
“SARA” procedure (ExxonMobil operation manual).
The saturate and aromatic fractions recovered from theliquid
chromatography were analysed for their biomarkerby gas
chromatography/mass spectrometry (GC/MS) usingthe selected ion
monitoring mode (SIM). Hexane was addedto each sample vial
containing the saturates and aromaticfractions to obtain
concentrations of 25𝜇g/𝜇L and 12.5 𝜇g/𝜇L,respectively. The samples
were mixed with a vortex mixerto agitate and then transferred to an
auto-sampler vial andcapped. Vials were then placed on the
auto-sampler to be runin an HP 6890 gas chromatograph silica
capillary column(30m × 0.25mm ID, 0.25 𝜇m film thickness) coupled
withHP 5973 Mass Selective Detector (MSD). The extract wasrapidly
injected into the gas chromatograph using a 10𝜇Lsyringe. Helium was
used as the carrier gas with oventemperature programmed from 80∘C
to 290∘C. The massspectrometer was operated at electron energy of
70 Ev, an ionsource temperature of 250∘C, and separation
temperature of250∘C. The chromatographic data were acquired using
MsChemstation software, version G1701BA for Microsoft NT.This
analysis was carried out at Exxon Mobil GeochemicalLaboratory,
Eket.
4.6. Aromatic Biomarker Parameters. According to Radkeet al.,
[29], MPI-1 (methyl phenanthrene index), DNR-1(dimethyl naphthalene
ratio), and MDR (methyl dibenzoth-iopene ratio) can be used as
source and maturity parameters.The necessary calculations were made
using the resultsobtained from peak identification and height of
aromaticbiomarkers of the studied wells (see Table 2).
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Journal of Geochemistry 5
Table 1: Data of TOC and rock-eval pyrolysis.
Sample IDnumber
Depth(meter)
SOM(ppm)
TOC(wt%)
S1(mg/g)
S2(mg/g)
S3(mg/g)
𝑇max(∘C) HI OI S2/S3
PI(S1/S1 + S2)
GP(S1 + S2)
V1 −224.5 ND 3.3 0.55 4.57 1.11 428 138 34 4.12 0.11 5.12V2 −223
3381 66.24 4.28 153.7 12.07 431 232 18 12.73 0.03 158.51V3 −222
3160 63.51 3.87 155.8 15.79 434 245 25 9.87 0.02 159.67V4 −220.5 ND
1.91 0.12 3.54 1.11 432 185 58 3.19 0.03 3.66V5 −227.5 467.8 7.49
0.54 17.71 1.67 433 237 22 10.6 0.03 18.25V6 −231.5 1904.8 8.52
0.71 14.25 2.33 426 167 27 6.12 0.05 14.95V7 −232.5 ND 3.2 0.28
2.66 1.31 428 83 41 2.03 0.1 2.94V8 −232 4095.2 69.51 7.75 169.61
14.33 429 244 20 11.84 0.04 177.36P1 −168.5 546.7 7.98 0.77 12.55
2.53 435 157 32 4.96 0.06 13.32P2 −169 ND 67.77 6.22 153.35 12.68
427 226 19 12.09 0.04 159.57P3 −172.5 250.1 2.24 0.37 3.7 1.3 431
165 58 2.85 0.09 4.07P4 −174.5 ND 1.61 0.31 2.25 1.43 431 142 90
1.57 0.12 2.56P5 −175.5 ND 1.96 0.25 2.09 0.49 427 107 25 4.27 0.11
2.34Notes: TOC=weight percentage organic carbon in rock. S1, S2 =mg
hydrocarbons per gram of rock. S3 =mg carbon dioxide per gram of
rock. GP = petroleumgeneric potential = S1 + S2. ND = not done. HI
= Hydrogen Index = S2 × 100/TOC. OI = oxygen index = S3 × 100/TOC.
𝑇max =
∘C. PI = production index =S1/(S1 + S2).
5. Organic Richness
According to Conford [30], adequate amount of organicmatter
measured as percentage total organic carbon is aprerequisite for
sediment to generate oil or gas. Shown inTable 1 are the results of
total organic matter content (TOC).The coal samples from both wells
show a higher organicrichness than shale. Nevertheless, both wells
have valuesabove the threshold of 0.5 wt% considered as minimum
forclastic source rocks to generate petroleum [31]. The
solubleorganic matter (SOM) of the samples generally exceeds500 ppm
except for samples P3 (EN 1325) and V5 (EN 1331)with SOM values of
250.1 and 467.8 ppm, respectively. Theseshow that the samples can
be classified as fair to excellentsource rocks. Based on the
quality definition of Baker [32], theorganic matter is adequate and
indicates good hydrocarbonpotential for the studied wells.
6. Organic Matter Type
The organic matter type in a sedimentary rock, among
otherconditions, influences to a large extent the type and quality
ofhydrocarbon generated due to different organic matter
typeconvertibilities [31]. The Hydrogen Index (HI) for the shaleand
coal samples ranges from 83 to 245mgHC/gTOC withan average value of
178mgHC/gTOC.This can be interpretedas type III (gas prone). The
plot of hydrocarbon potentialversus TOC (Figure 4) indicates type
II/III organic matterwhich means a potential to generate oil and
gas.Themajorityfall within the type III organic matter indicating
that gas willdominantly be generated, with little oil. Peters [33]
suggestedthat at thermal maturity equivalent to vitrinite
reflectanceof 0.6% (𝑇max 435
∘C), rocks with HI > 300mgHC/gTOCproduce oil, those with HI
between 150mgHC/gTOC and300mgHC/gTOCproduce oil and gas,
thosewithHI between
Type IV, inert
10 20 30 40 50 60 70 80
300
250
200
150
100
50
0
Well 1325Well 1331
Rem
aini
ng h
ydro
carb
on p
oten
tial S2
(mgH
C/g)
Type IIoil-proneusually marine
Mixed type II-IIIoil-gas-prone
Type IIIgas-prone
Type Ioil-proneusually lacustrine
Total organic carbon—TOC (wt.%)
Figure 4: A plot of hydrocarbon potential against TOC.
50mgHC/gTOC and 150mgHC/gTOC produce gas, andthose with HI <
50mgHC/gTOC are inert. From this study,the range of HI is from 83
to 245 for the shales and coal. Thisindicates oil and gas
prone.
Petroleum generating potential (GP) is the sum of S1
and S2values obtained from rock eval pyrolysis (Table 1).
The values obtained range from 2.34 to 177.36. According toDyman
et al. [34], values greater than 2 kgHC/ton of rockindicate good
source rock.This suggests oil and gas potential.
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6 Journal of Geochemistry
Table2:Datao
fmolecular
parametersfor
thes
tudied
wells.
Sample
ID𝑇𝑠/(𝑇𝑠+𝑇𝑚)
Oleanane/ho
pane
Hop
ane
C 30/C 29
Hop
ane
C 32
Hop
ane
C 29
Hop
ane
C 30
Sterane
C 29
Tetracyclic/tr
icyclic
C 24
Dia/Reg
C 27
Tri
C 19/C 20
ratio
DNR
TMNR
MPI-1
MDR
P10.02
0.62
1.98
0.49
0.49
0.52
0.15
1.50.93
1.29
2.15
0.19
0.47
0.99
P30.19
0.18
0.17
0.5
0.32
0.2
0.26
2.25
0.55
1.41
2.12
0.17
0.76
4.21
V8
0.01
0.02
1.01
0.53
0.55
0.57
0.13
1.84
0.38
1.37
1.64
0.48
0.34
2.68
V6
0.05
0.12
1.32
0.49
0.37
0.42
0.24
1.74
1.28
0.75
2.25
0.5
0.26
1.04
V5
0.02
0.03
1.12
0.49
0.51
0.56
0.14
2.22
0.27
1.09
0.75
0.21
0.24
2V2
0.05
0.08
0.72
0.56
0.5
0.51
0.27
1.86
0.44
1.12.51
0.44
0.17
2.02
V3
0.01
0.01
1.09
0.54
0.57
0.59
0.16
2.16
0.55
1.34
1.54
0.48
0.14
1.2Notes:D
NR-1=
(2,6DMN+2,7DMN)/1,5
DMN.T
MNR=(1,3,7TM
N)/(1,3,7TM
N+1,2
,5TM
N).MPI-1=1,5
(2MP+3M
P)/(P+1M
P+9M
P).M
DR=4M
DBT
/1MDBT
.4MDBT
=4methyld
ibenzothiopene.
2,6/2,7DMN=2,6/2,7dimethyln
aphthalene.1,5DMN=1,5
dimethyln
aphthalene.1,3,7=1,3
,7trim
ethyln
aphthalene.1/2/3/9
MP=1/2
/3/9
methylphenanthrene.
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Journal of Geochemistry 7
0
100
200
300
400
500
600
700
800
900
1000
400 425 450 475 500
Hyd
roge
n In
dex
( HI,
mgH
C/gT
OC)
Immature PostmatureMature
+
++ ++
+
∗∗ ∗∗∗
∗∗
∗
Type Ioil-prone
usually lacustrine
Type IIoil-prone
usually marine
Type II-III
Type IIIgas-prone
Type IVinert
Con
dens
ate-
wet
gas
zone
Dry gas window
Oil window
Well 1325Well 1331
Tmax (∘C)
Figure 5: A plot of Hydrogen Index against 𝑇max for the
studiedwells.
7. Thermal Maturity
The degree of thermal evolution of the sedimentary organicmatter
was derived from Rock Eval 𝑇max and biomarkerparameter. According
to Peters et al., [35], biomarkers (geo-chemical fossils) can
provide information on the organicsource materials, environmental
conditions during its depo-sition, the thermal maturity experienced
by a rock or oil, andthe degree of biodegradation.
The 𝑇max values (Table 1) range from 425 to 435∘C. These
indicate that the shales and coal range from immature to
earlypeak mature (oil window) but on the average are immature.The
interpretation is in line with those given by Peters [33],Dow [36],
and Miles [37]. This is further highlighted by theplot of HI versus
𝑇max (Figure 5).𝑇𝑚(C27: 17𝛼(H)-22,29,30-Trisnorhopane) represents
bio-
logically produced structures and 𝑇𝑠(C27: 18𝛼(H)-22,29,30-
Trisnorneohopane) generated in sediments and rocks bydiagenetic
or thermal process or both. 𝑇
𝑠/(𝑇𝑠+ 𝑇𝑚) is a
ratio used as both source and maturity parameters. The𝑚/𝑧 191
(hopanes) (Figure 6) and 217 steranes (Figure 7)chromatograms of
all the samples are similar. H
30(hopanes)
are the most abundant in the 𝑚/𝑧 191 chromatogram.The maturity
and source parameters derived from thehopane distributions in the
shales and coals are shown inTables 2 and 4. Also shown are
calculated parameters ofaromatic biomarkers. Parameters such as
MPI-1 (methylphenanthrene index), DNR-1 (dimethyl naphthalene
ratio),TMNR (trimethyl naphthalene ratio), and MDR
(methyldibenzothiopene ratio) with respective range of values
0.14–0.76, 0.75–2.51, 0.17–0.50, and 0.99–4.21 all indicate that
thesamples are immature to marginally mature [29]. Accordingto
Sonibare et al. [38], the abundance of 1,2,5 TMN
(trimethylnaphthalene) suggests a significant land plant
contribution tothe organic matter (Figure 8).
Some 𝑛-alkane ratios can be used to estimate the thermalmaturity
of sediments [39]. Pristane/𝑛C
17and phytane/𝑛C
18
25.00 30.00 35.00 40.00 45.00 50.00 55.00 60.00 65.000
50000100000150000200000250000300000350000400000450000500000
Time
Time
Abun
danc
eAb
unda
nce
Ion 191.00 (190.70 to 191.70): V6S.D
25.00 30.00 35.00 40.00 45.00 50.00 55.00 60.00 65.000
50000100000150000200000250000300000350000400000450000500000550000600000650000
Ion 191.00 (190.70 to 191.70): V8S.D
T19
T20
T21
T22
T23
T24 T2
5
Tet2
4T2
6ST2
8R
T30S
H28
H29
H30
NM
Mor
H31
SH
31R
H32
SH
32R
H33
SH
33R
H34
S
T19 Tet2
4
XH
29N
MH
30M
or H31
SH
31R
H32
SH
32R
H33
SH
33R
H43
R
T20
T21
T22 T2
4 T28R
T30S
Ts
Tm
Ts
Tm
Figure 6: 𝑚/𝑧 191 chromatograms showing the distribution
oftricyclic triterpenes and hopanes in the samples.
Table 3: Gas chromatographic data showing values of
n-alkanesratio and their CPI.
Sample ID Pr/Ph Pr/nC17 Ph/nC18 CPI OEP-1 OEP-2EN 1331 (V2) 5.88
0.8 0.57 1.57 0.4 0.57EN 1331 (V5) 7.26 1.98 0.33 1.83 0.43 0.56EN
1331 (V6) 8.97 3.91 0.46 1.53 0.4 0.57EN 1325 (P1) 5.5 1.62 0.4
1.69 0.56 0.57EN 1325 (P3) 5.08 1.1 0.2 1.75 0.43 0.61Notes: CPI =
carbon preference index = 2(C23 + C25 + C27 + C29)/(C22 +2(C24 +
C26 + C28) + C30). OEP-1 = (C21 + C23 + C25)/(4C22 + 4C24). OEP-2=
(C25 + C27 + C29)/(4C26 + 4C28). OEP = odd-even predominance.
can be used to calculate thermal maturity. For the stud-ied
wells, the Pr/𝑛C
17values ranged between 0.8 and 3.91
(Table 3); this falls in the immature zone. Ph/𝑛C18
valuesranged from 0.2 to 0.57, which is below the threshold
value,indicating immature organic matter.
Carbon preference index (CPI) is the relative abundanceof odd
versus even carbon-numbered 𝑛-alkanes and can alsobe used to
estimate thermal maturity of organic matter [40].In this study, the
CPI values obtained range from 1.53 to 1.83(Table 3). Hunt [41] has
pointed out that CPI considerably
-
8 Journal of Geochemistry
25.00 30.00 35.00 40.00 45.00 50.00 55.00 60.00 65.000
500010000150002000025000300003500040000450005000055000
Time
Ion 217.00 (216.70 to 217.70): P1S.D
25.00 30.00 35.00 40.00 45.00 50.00 55.00 60.00 65.000
50001000015000200002500030000350004000045000500005500060000
Time
Ion 217.00 (216.70 to 217.70): P3S.D
Abun
danc
eAb
unda
nce
i i28
bR
d27a
Sd2
7bS
i27
bR+
d29
bS
d27b
R
i i28
bR
d27a
Sd2
7bS
i27
bR+
d29
bS
S29
aR+
S30
aSS29
aR+
S30
aS
Figure 7: 𝑚/𝑧 217 chromatograms showing the distribution
ofsteranes in samples P3 and V5.
6.00 8.00 10.00 12.00 14.00 16.00 18.00 20.00 22.00 24.000
100020003000400050006000700080009000
100001100012000130001400015000160001700018000190002000021000
Time
Abun
danc
e
Ion 170.00 (169.70 to 170.70): V5A.D (+)
1,3
,6TM
N1
,2,7+1
,6,7
TMN
1,2
,6TM
N 1,2
,5TM
N
1,2
,4TM
N
Figure 8:𝑚/𝑧 170 mass chromatogram showing the distribution
ofnaphthalene in representative sample V5 (ENUGU 1331).
greater than 1.0 shows contribution from terrestrial
continen-tal plants and immaturity. Maxwell et al., [42] have
shownthat strong odd/even bias of heavy 𝑛-alkanes is indicativeof
sediment immaturity. For this study, the odd numbered𝑛-alkanes are
more abundant than the even numbered 𝑛-alkanes, indicating that the
sediments are immature. Theodd-even predominance (OEP) values are
less than 1.0, thisis indicative of low maturity [43].
0.4
0.35
0.3
0.25
0.2
0.15
0.1
0.05
00 0.1 0.2 0.3 0.4 0.5 0.6 0.7
Anoxic carbonate
Anoxic shale
Thermal maturation
Eh effect
PH effect
Suboxic strata
Dia/(dia + reg) C27 steranes
Ts/(Ts+Tm
)
Figure 9: A plot of 𝑇𝑠/(𝑇𝑠+ 𝑇𝑚) versus dia/(dia + reg)C
27steranes
showing the environment inwhich the organicmatter was
deposited(After [44]).
8. Palaeodepositional Environment
Moldowan et al. [44] have indicated that the presence
ofbisnorhopane and diasterane is indicative of suboxic con-ditions.
A plot of 𝑇
𝑠/(𝑇𝑠+ 𝑇𝑚) versus dia/(dia + reg)C
27
steranes, as shown in Figure 9, is indicative of a
suboxiccondition. Pristane/phytane (Pr/Ph) ratio of sediments can
beused to infer depositional environment [35]. Pr/Ph ratios <1
indicate anoxic depositional environment, while Pr/Ph >1
indicate oxic conditions. Pr/Ph 1 < 2 indicate a marine-sourced
organic matter and Pr/Ph > 3 indicates terrige-nous organic
matter input with oxic conditions. The valuesobtained from the
studied wells ranged from 5.08 to 8.97, thusindicating that the
samples have terrigenous-sourced organicmatter deposited in an
oxidizing environment. CrossplotsPr/𝑛C
17versus Ph/𝑛C
18(Figure 10) reveal that the sediments
were deposited in an oxidizing environment and are
fromterrestrial and peat environments. This is consistent with
thesamples as some of them are of coal environment.
Dahl et al. [45] reported that a low ratio of homophaneindex is
characteristic of a suboxic environment (Table 4).On the other
hand, Pr/Ph ratio tend to be high (>3) inmore oxidizing
environment such as in swamps. High Pr/Phvalues from the work
indicate a terrigenous input under oxicconditions. A large
proportion of the results point to the factthat a suboxic condition
prevailed in the deposited sediments.These indicate that a
significant portion of the facies wereprobably deposited in an
offshore, shallow to intermediatemarine environment under suboxic
water conditions whichprobably had no connection with the
widespread Cretaceousanoxic events but are related to
theCampanian-Maastrichtiantransgression.
9. Summary and Conclusion
Detailed geochemical analysis of the coal and shale
intervalsgotten from the Anambra Basin, Nigeria, has been used
-
Journal of Geochemistry 9
10
1
0.10.1 101
Samples
Matur
ation
Terres
trial o
rganic
matt
er
Peat co
al env
ironm
ent
Mixed
organ
ic sou
rce
Marin
e orga
nic m
atter
Biodeg
radati
on
Oxidizing
Reducing
Ph/nC18
Pr/n
C17
Figure 10: Plot of pristane/𝑛C17versus phytane/𝑛C
18(After [44]).
Table 4: Results and interpretations of geochemical fossils.
Parameters Values RemarksC29steranes
20S/20S + 20R 0.13–0.27 Immature [46]
C27diasteranes/
steranes 0.27–1.28 Immature [47]
C29hopanes𝛽𝛼/𝛼𝛽 0.32–0.57 Immature [44]
C30𝛽𝛼/𝛼𝛽
(hopanes) 0.20–0.59 Immature [39]
𝑇𝑠/(𝑇𝑠+ 𝑇𝑚) 0.01–0.19 Immature [39]
C30/C29𝑇𝑠
0.17–1.98 Suboxic conditions [46]C35homophane
Index C34 and C35 lowSuboxic conditions, highEh, terrigenous
input [45]
Diasterane/reg.sterane 0.33–1.2
Suboxic to oxic conditions[47]
to investigate the aspects of their molecular fossil.
Thelithostratigraphic sequence penetrated by both wells (Enugu1325
and 1331) consists of shales, coal, and siltstones. Theshales are
dark grey and fissile. The siltstones are brown tolight grey in
colour while the coal is blackish.
Organic richness of the samples was deduced from SOMand TOC as
fair to excellent. The organic matter type ispredominantly
terrestrial. This is based on the HI values, HI-𝑇max plot, the
presence of oleanane, the abundance and pre-dominance of C
29, C35homophane index, and the abundance
of 1,2,5 Trimethyl Naphthalene.Biomarker parameters were used to
determine the degree
of thermal evolution of the sediment organic matter. Thepresence
of bisnorhopane, diasterane, plot of 𝑇
𝑠/(𝑇𝑠+ 𝑇𝑚)
against dia/(dia + reg)C27sterane and the homophane index
all indicate suboxic and high Eh conditions.Discrepancies were
observed in the results used in the
interpretation of physicochemical conditions prevailing inthe
deposited sediments. These varied between oxic andsuboxic
conditions. It is thereby concluded that the lithologiesfrom the
core samples are those of the Mamu Formation andEnugu-Shale Group
which were deposited in a partial or nor-mal marine (suboxic to
oxic water conditions) environment.There is no strong evidence to
show that the shales and coalshave expelled petroleum although they
possess what it takesto be economic, largely in terms of gas, thus
presenting a goodprospect.
Conflict of Interests
The author declares that there is no conflict of
interestsregarding the publication of this paper.
Acknowledgments
The author is grateful to the Nigerian Geological SurveyAgency
(NGSA), Kaduna, for provision of borehole sam-ples. The author
remains grateful to the members of staffof Weatherford Geochemical
Laboratory, Texas, USA, andExxonMobil Geochemical Laboratory, Eket,
Nigeria, for thetechnical services rendered. The author’s sincere
gratitudegoes to Dr.M. E. Nton of theDepartment of Geology,
Univer-sity of Ibadan, for his suggestions.The author also thanks
theanonymous reviewers for their constructive comments whichled to
improving this paper.
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