research article use of geochemical fossils as indicators of … · 2019. 7. 31. · research...

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

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.

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.


Lithologic description


Coal, blackish Coal, blackish

Siltstone, brown to light grey



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).


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.


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.


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


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


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.

References

[1] I. M. Akaegbobi, “The crab’s eye-view of the organic sedimento-logical evolution of the Anambra Basin, Nigeria: Hydrocarbonsource potential and economic implications,” in Faculty Lecture,pp. 1–32, Ibadan University Press, Ibadan, Nigeria, 2005.

[2] A. Whiteman, Nigeria: Its Petroleum Geology, Resources andPotential, Vol. 1, Grantman and Trontman, London, UK, 1982.

[3] T. J. A. Reijers, Selected Chapters on Geology, SPDC Nigeria,1996.

[4] I. Nexant, “National oil and gas policy: a draft report preparedfor the Bureau of Public Enterprises (Nigeria),” Tech. Rep.,Nexant Griffin House, London, UK, 2003.

[5] R. C. Murat, “Stratigraphy and paleogeography of the Cre-taceous and Lower Tertiary in southern Nigeria,” in AfricanGeology, T. F. J. Dessauvagie and A. Whiteman, Eds., pp. 257–266, Ibadan University Press, Ibadan, Nigeria, 1972.

[6] K. C. Burke, “The African plate,” South African Journal ofGeology, vol. 99, no. 4, pp. 341–409, 1996.

[7] K. C. Burke, T. F. J. Dessauvagie, and A. J. Whiteman, “Geologichistory of the Benue valley and adjacent areas,” in AfricanGeology, T. F. J. Dessauvagie and A. J. Whiteman, Eds., pp. 187–218, University of Ibadan Press, Ibadan, Nigeria, 1972.

[8] J. D. Fairhead and C. M. Green, “Controls on rifting in Africaand the regional tectonic model for the Nigeria and East Nigerrift basins,” Journal of African Earth Sciences, vol. 8, no. 2–4, pp.231–249, 1989.


[9] J. Benkhelil, “The origin and evolution of the Cretaceous BenueTrough (Nigeria),” Journal of African Earth Sciences, vol. 8, no.2–4, pp. 251–282, 1989.

[10] W. Khunt, J. P. Herbin, J. Thurow, and J. Wiedmann, “Westernmediterranean and along the adjacent Atlantic margin,” inDeposition of Organic Facies, A. Y. Hue, Ed., AAPG Studies inGeology no. 30, pp. 138–159, 1990.

[11] K. C. Short andA. J. Stauble, “Outline of geology ofNigerDelta,”AAPG Bulletin, vol. 51, no. 5, pp. 761–779, 1967.

[12] G. C. Obi and C. O. Okogbue, Sedimentary Response to Tec-tonism in the Campanian-Maastrichtian Succession, AnambraBasin, Southeastern Nigeria, University of Nigeria, Nsukka,Nigeria, 2001.

[13] A. Avbovbo and E.O. Ayoola, “Petroleumprospects of southernNigeria’s Anambra Basin,”Oil and Gas Journal, vol. 79, pp. 334–348, 1981.

[14] O. Agagu and C. M. Ekweozor, “Source rocks characterisationsof Senonian shales in the Anambra Basin,” Journal of MiningGeology, vol. 19, pp. 52–61, 1982.

[15] G. I. Unomah, Petroleum geochemical evaluation of the uppercretaceous shales in the lower benue trough [Ph.D. thesis],Department of Geology, University of Ibadan, Ibadan, Nigeria,1989.

[16] G. I. Unomah and C. M. Ekweozor, “Petroleum source rockassessment of the campanian Nkporo shale, Lower BenueTrough, Nigeria,”NAPE Bulletin, vol. 8, no. 2, pp. 172–186, 1993.

[17] C.M. Ekweozor, “Investigation of geohistory ofAnambra Basin,part 5 case history 3,” in Basic Geochemistry, Lecture Presentedat the Oil and Gas Academy, Port Harcourt, Nigeria, May 2006.

[18] P. U. Iheanacho, Subsurface evaluation of source rock andhydrocarbon potential of the Anambra Basin, SoutheasternNigeria [M.S. Dissertation], Department of Geology, Universityof Ibadan, Ibadan, Nigeria, 2010.

[19] R. A. Reyment, Aspect of the Geology of Nigeria, University ofIbadan Press, 1965.

[20] O. K. Agagu, E. A. Fayose, and S. W. Petters, “Stratigraphyand sedimentation in the senonian Anambra Basin of EasternNigeria,” Nigeria Journal of Mining Geology, vol. 22, no. 1-2, pp.26–26, 1985.

[21] E. E. Nyong, “Cretaceous sediments in the Calabar Flank,”in Geological Excursion Guide to Oban Massif, Calabar Flankand Mamfe Embayment, Southeastern Nigeria. 31st AnnualConference, B. N. Ekwueme, E. E. Nyong, and S.W. Petters, Eds.,pp. 14–25, Nigerian Mining and Geoscience Society, 1995.

[22] M. N. Tijani, M. E. Nton, and R. Kitagawa, “Textural andgeochemical characteristics of the Ajali Sandstone, AnambraBasin, SE Nigeria: implication for its provenance,” ComptesRendus Geoscience, vol. 342, no. 2, pp. 136–150, 2010.

[23] O. S. Adegoke, “Eocene stratigraphy of southernNigeria,” in 3rdColloque sur l'Eocene, vol. 69, pp. 22–48, Bureau de RecherchesGéologiques et Minières, 1969.

[24] C. A. Kogbe, “Paleogeographic history of Nigeria from Albiantimes,” inTheGeology of Nigeria, C. A. Kogbe, Ed., pp. 237–252,University of Ife, 1975.

[25] C. S. Nwajide and T. J. A. Reijers, “Sequence architecture ofthe Campanian Nkporo and Eocene Nanka formation of theAnambra Basin,Nigeria,”NAPEBulletin, vol. 12, no. 1, pp. 75–87,1996.

[26] I. Arua, “Paleocene macrofossils from the Imo Shale in Anam-bra Basin, Nigeria,” Journal of Mining and Geology, vol. 17, pp.81–84, 1980.

[27] T. J. A. Reijers, S. W. Petters, and C. S. Nwajide, “The niger deltabasin,” in African Basins, R. C. Selley, Ed., pp. 151–172, Elsevier,Amsterdam, The Netherlands, 1997.

[28] G. Nichols, Sedimentology and Stratigraphy, Wiley-Blackwell,West Sussex, UK, 2009.

[29] M. Radke, D. H. Welte, and H. Willsch, “Maturity parametersbased on aromatic hydrocarbons: influence of the organicmatter type,” Organic Geochemistry, vol. 10, no. 1–3, pp. 51–63,1986.

[30] C. Conford, “Source rock and hydrocarbons of the North Sea,”in Introduction to The Petroleum Geology of The North Sea, K.W. Glenuie, Ed., pp. 197–236, 1986.

[31] B. G. Tissot and D. H. Welte, Petroleum Formation and Occur-rence: A New Approach Oil and Gas Exploration, Springer,Berlin, Germany, 1984.

[32] D. R. Baker, “Organic geochemistry and geological interpreta-tions,” Journal of Geological Education, vol. 20, no. 5, pp. 221–234, 1974.

[33] K. E. Peters, “Guidelines for evaluating petroleum sourcerocks using programmed pyrolysis,” American Association ofPetroleum Geologists Bulletin, vol. 70, no. 3, pp. 318–329, 1986.

[34] T. S. Dyman, J. G. Palacas, R. G. Tysdal, W. J. Perry Jr., and M.J. Pawlewicz, “Source rock potential of middle cretaceous rocksin Southwestern Montana,” AAPG Bulletin, vol. 80, no. 8, pp.1177–1184, 1996.

[35] K. E. Peters, C. C. Walters, and J. M. Moldowan, BiomarkerGuide: Biomarker and Isotopes in Petroleum Exploration andEarth History, Cambridge University Press, Cambridge, UK,2005.

[36] W. G. Dow, “Kerogen studies and geological interpretations,”Journal of Geochemical Exploration, vol. 7, pp. 79–99, 1977.

[37] J. A. Miles, Illustrated Glossary of Petroleum Geochemistry,Oxford Science Publication, Oxford University Press, 1989.

[38] O. O. Sonibare, T. Adedosu, A. O. Ekundayo, and D. Jarvie,“Hydrocarbon potential and organic geochemistry of coalsfrom Benue Trough, Nigeria,” Journal of Applied SciencesResearch, vol. 4, no. 11, pp. 1511–1520, 2008.

[39] H. L. ten Haven, J. W. de Leeuw, J. Rullkötter, and J. S. S.Damsté, “Restricted utility of the pristane/phytane ratio as apalaeoenvironmental indicator,” Nature, vol. 330, no. 6149, pp.641–643, 1987.

[40] K. E. Peters and J. W. Moldowan, The Biomarker Guide: Inter-preting Molecular Fossils in Petroleum and Ancient Sediments,Prentice Hall, Englewood Cliffs, NJ, USA, 1998.

[41] J. M. Hunt, Petroleum Geochemistry and Geology, W. H. Free-man and Company, San Francisco, Calif, USA, 1979.

[42] J. R. Maxwell, C. T. Pillinger, and G. Eglinton, “Organicgeochemistry,” Quarterly Reviews, Chemical Society, vol. 25, no.4, pp. 571–628, 1971.

[43] E. S. Scalan and J. E. Smith, “An improved measure of the odd-even predominance in the normal alkanes of sediment extractsand petroleum,” Geochimica et Cosmochimica Acta, vol. 34, no.5, pp. 611–620, 1970.

[44] J. M. Moldowan, J. Dahl, B. J. Huizinga et al., “The molecularfossil record of oleanane and its relation to angiosperms,”Science, vol. 265, no. 5173, pp. 768–771, 1994.

[45] J. E. Dahl, J. M. Moldowan, S. C. Teerman, M. A. McCaffrey,M. Pena, and C. E. Stelting, “Source rock quality determinationfromoil biomarkers—an example from theAspen shale, Scully’sGap, Wyoming,” American Association of Petroleum GeologistBulletin, vol. 78, no. 10, pp. 1507–1526, 1994.


[46] W.-Y. Huang and W. G. Meinschein, “Sterols as ecologicalindicators,”Geochimica et Cosmochimica Acta, vol. 43, no. 5, pp.739–745, 1979.

[47] I. Rubinstein, O. Sieskind, and P. Albrecht, “Rearranged sterenesin a shale: occurrence and simulated formation,” Journal of theChemical Society: Perkin Transactions, vol. 1, no. 19, pp. 1833–1836, 1975.

Submit your manuscripts athttp://www.hindawi.com

Hindawi Publishing Corporationhttp://www.hindawi.com Volume 2014

ClimatologyJournal of

EcologyInternational Journal of


EarthquakesJournal of


Hindawi Publishing Corporationhttp://www.hindawi.com

Applied &EnvironmentalSoil Science

Volume 2014

Mining


Journal of

Hindawi Publishing Corporation http://www.hindawi.com Volume 2014

International Journal of

Geophysics

OceanographyInternational Journal of


Journal of Computational Environmental SciencesHindawi Publishing Corporationhttp://www.hindawi.com Volume 2014

Journal ofPetroleum Engineering


GeochemistryHindawi Publishing Corporationhttp://www.hindawi.com Volume 2014

Journal of

Atmospheric SciencesInternational Journal of


OceanographyHindawi Publishing Corporationhttp://www.hindawi.com Volume 2014

Advances in


MineralogyInternational Journal of


MeteorologyAdvances in

The Scientific World JournalHindawi Publishing Corporation http://www.hindawi.com Volume 2014

Paleontology JournalHindawi Publishing Corporationhttp://www.hindawi.com Volume 2014

ScientificaHindawi Publishing Corporationhttp://www.hindawi.com Volume 2014


Geological ResearchJournal of


Geology Advances in

research article use of geochemical fossils as indicators of … · 2019. 7. 31. · research...

Documents