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USE OF STABLE CARBON ISOTOPE IN CHARACTERIZATION OF TAR SAND

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Akinmosin, A., Osinowo, O.O. and Adio, N. A., 2010. Use of Stable Carbon Isotope in Characterization of Tar Sand

Deposit in Southwestern Nigeria.

317

Journal of Applied Sciences in Environmental Sanitation, 5 (4): 317-328.

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Research Paper

USE OF STABLE CARBON ISOTOPE IN CHARACTERIZATION OF TAR SAND

DEPOSIT IN SOUTHWESTERN NIGERIA

AKINMOSIN, A.1*, OSINOWO, O.O.2 and ADIO, N. A.3

1Department of Geosciences, University of Lagos, Lagos, Nigeria. 2Department of Geology,University of Ibadan, Ibadan, Nigeria.

3Olabisi Onabanjo University, Ago Iwoye, Ogun State, Nigeria. P.M.B. 2002. *Corresponding Author: Phone +2348035826979; E-mail: [email protected]

Received: 14th January 2010; Revised: 13th March 2010; Accepted: 19th August 2010

Abstract: Carbon isotope abundance of the saturated and aromatic hydrocarbon components of the tar sand deposit in parts of southwest Nigeria was measured. A total of eighteen seepage samples were collected from different localities in which the tar sands outcrop. The isotopic data together with chemical composition, physical characteristics, and geological information were used to investigate the relationships between various exposures, their source, as well as environment of deposition.The stable isotope values obtained fall into two categories of heavy (>-24‰) and light (<-26 to -30‰) groups. The bituminous sands are enriched in 13C in both saturates and aromatic hydrocarbons (-28.7 to -24.1‰ saturates; -27.53 to -23.59‰ aromatics). A plot of the 13C values of saturates against the aromatics reveals that the bitumen content was generated from marine organic matter. The negative trend in the 13C values also gives a significant indication that the source rock was deposited during a regressive episode.The API Gravity values at different localities range from 150 – 200, indicating that the bitumen is a product of moderate biodegradation of conventional crude oil.

Keywords: Stable isotope, biodegradation, tar sands, bitumen, environment

INTRODUCTION

Asphalt impregnated sandstones, otherwise referred to as oil sand (tar sand) and active oil

seepages occur in southwestern Nigeria within the Eastern Dahomey (Benin) basin, a marginal pull apart [1] or marginal sag [2] basin. The oil sand outcrops in an E-W belt, approximately

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120km long and 4-6km wide, extending from Edo/Ondo-Ogun States [3]. The physico-chemical characteristics of the tar sands so far sampled mainly from outcrops and coreholes in the Agbabu/Ore areas in Ondo state have been extensively reported. The salient aspects of the comprehensive information published within the last two decades covering oil saturation, bitumen ultimate analysis, stock-tank properties, calorific values, etc have been published [4-7]. In summary, the bitumen content or oil saturation of the sands is variable but averages 12-14wt. % for the medium-high grade horizons. Fischer assay pyrolysis yield of the bituminous sands has the following average composition (%vol): - Heavy oil, 76%; Middle Oil, 19.4%; Naphtha 4.6%. According to the classification of Tissot and Welte [8], the oil is Extra-Heavy, especially in view of its low API gravity, >200, and elevated content of combined resins and asphaltenes, (generally<50wt.%) implying very substantial viscosity, possibility in the range, 104 -105 centipoises. The total hydrocarbon fraction (saturated plus aromatic alkanes), on the average, generally corresponds to <50wt. % of bitumen as is the case with similar non-conventioinal oils from other parts of the world.

Stable isotopes of hydrogen and carbon have been used in studies of sources of oil [9-13], gas [14], and coals [15-16], and numerous reviews of δ13Coil as a source indicator have been published [10-12, 17-19]. More recently, isotopic analyses of oils have been integrated with other geochemical parameters to enhance the accuracy of source assignments [13, 20]. The diverse factors influencing carbon isotopic compositions of oils can be at least partially dissected using compound d-specific isotopic analyses [21], allowing us more straightforward interpretations of origins [22-24].

Whole oil chemical composition analysis are commonly available, and to further examine their values and applications, this research work focuses specifically on carbon isotopic composition obtained from a representative group of tar from the eastern part of Dahomey basin, a region that is noted for the presence of abundant tar sand deposit with compositional variability. So far, no work has been published on the isotopic composition of the tar in the eastern part of Dahomey basin. This work reveals that integration of isotopic information with the geochemical, geological, and stratigraphical knowledge of Eastern Dahomey basin can add significantly to those interpretations. MATERIALS AND METHODS Geology, Stratigraphy of the Dahomey Basin

The study area extends from the western part of Ijebu-Ife, to the western part of Okitipupa (Fig. 1). This spans across locations like Loore village, Ogbere area, Gbegude village, and Igbotako area, all in Southwestern Nigeria.

The Benin (Dahomey) Basin constitutes part of a system of West African peri-cratonic (margin sag) basin [1, 2] developed during the commencement of the rifting, associated with the opening of the Gulf of Guinea, in the Early Cretaceous to the Late Jurassic [25-26]. The crustal separation, typically preceded by crustal thinning, was accompanied by an extended period of thermally induced basin subsidence through the Middle – Upper Cretaceous to Tertiary times as the South American and the African plates entered a drift phase to accommodate the emerging Atlantic Ocean [27-28].

The Ghana Ridge, presumably and offset extension of the Romanche Fracture Zone, binds the basin to the west while the Benin Hinge Line, a Basement escarpment which separates the Okitipupa Structure from the Niger Delta basin binds it to the east. The Benin Hinge Line supposedly defines the continental extension of the Chain Fracture Zone (Fig. 2).



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Fig. 1: Map showing location of the study area and the sampling points.

Fig. 2: General Geological Framework of the Dahomey Basin (Modified from Bilman [29]).



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The onshore part of the basin covers a broad arc-shaped profile of about 600 km 2 in extent.

The onshore section of the basin attains a maximum width, along its N-S axis, some 130 km

around the Nigerian – Republic of Benin border. The basin narrows to about 50 km on the

eastern side where the basement assumes a convex upwards outline with concomitant thinning

of sediments. Along the northeastern fringe of the basin where it rims the Okitipupa high is a

brand of tar (oil) sands and bitumen seepage.

The lithostratigraphic units of the Cretaceous to Tertiary sedimentary sequence of eastern

margin of Dahomey basin according to Omatsola and Adegoke [30] are as follows:

Ise Formation

The oldest formation in Abeokuta Group is referred to as Ise and is uncomfortably overlaps the

Precambrian basement complex. It has basal conglomerate, gritty to medium-grained loose sand,

capped by kaolinitic clay [30-31]. The maximum thickness of the member is about 1865m and

more than 600m of it was penetrated by Ise - 2 borehole. The age has been given to be

Neocomian.

Afowo Formation

Afowo Formation based on the palynomorph content is Neocomian. Afowo Formation succeeds

the Ise Formation. Afowo Formation indicates the commencement of deposition in a transitional

environment after the entire basal and continental Ise Formation. The sediments are composed of

interbedded sands, shales and clays, which range from medium to fine grains in sizes [30-31]. It

has been found to be bituminous in both surface and sub-surface sections. The age is

Mastrichitian.

Araromi Formation

Araromi Formation, the topmost unit of the Abeokuta Group. Sediments of the Araromi Formation

represent the youngest topmost sequence in the group. The formation is composed of shales,

fine-grained sand, thin interbeds of limestone, clay and lignite bands [30-31]. It is an equivalence

of a unit known as Araromi shale by Reyment [32]. The shales are grey to black in colour, marine,

and rich in organic matter. The age ranges from Maastrichtian to Paleocene.

Imo Group

This group consists of the two lithostratigraphic units which are: Ewekoro Formation and Akinbo

Formation. Ewekoro Formation directly overlies the Abeokuta Group as it has been observed

from the sections at Ewekoro and Sagamu quarries as well as the cored sections at Ibeshe. It is

made up of grayish white and occasionally greenish limestone which is sandy toward the base

and having a thickness that varies between 15-30m. This formation is dated Paleocene age.

Akinbo Formation is mostly found in the western part of the Imo Group, directly overlying the

Ewekoro Formation. It constitutes the upper part of the Imo Group. It is essentially greenish,

highly fossiliferous and thickly laminated. The age of Akinbo Formation is considered Paleocene.

Ilaro Formation

It consists of coarse to fine grained sands, clays and shales with occasional thin bands of

phosphate beds being observed at Ilo. The formation is Eocene in age.



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Coastal Plain Sands (Benin Sand Formation) The coastal plain sand overlies the Ilaro Formation but evidence for this is lacking [33]. The coastal plain sands consist of very poorly sorted, clayey, pebbly sands, sandy clay and rare thin lignite. They are the basal continental beds of the Abeokuta Group. Coastal plain sands range in age from Oligocene to Pleistocene. Recent Alluvium This is the youngest unit in the Eastern Dahomey basin. It has been thought to overlie the Ilaro Formation, but convincing evidence for this is lacking [33]. The exposure at the road cuttings between Ofada and Mokoloki on the Ogun River reveals coarse clayey sorted sands with clay lenses and occasional pebble. Isotopic Analysis

The stable isotopic composition of the tar seepages was determined in the laboratory by using an elemental analyzer (EA1110 CHN, Thermo Scientific) coupled with an isotope ratio mass spectrometer (VG Sira Series II), utilizing a custom open-split sample introduction system. The mass spectrometer is operated in continuous flow mode, with a helium carrier gas delivering the sample and reference peaks, alternating throughout an automated run. API Gravity

The samples were analysed for its specific gravity from which the American Petroleum Institute (API) gravity was calculated using the formula as follows:

API gravity= {141.5/specific gravity at 60ºF} – 131.5 The API gravity provides information on the level of oil biodegradation as well as how heavy

the oil is. RESULTS AND DISCUSSION

The results of the stable carbon isotopes analyses performed on the tar sand samples (seepages) are presented in the Table 1, while Figure 3 shows the isotopic plots across the study area. Carbon Isotope Trend and Sea Level Changes

A correlation between carbon isotope trend and sea level has been noted by several authors [34-36]. Recently, Follimi et al. [36] proposed a theoretical feedback mechanism linking carbon isotope trend with sea level changes via complex interplay between extrinsic factors (volcanism and climate) and intrinsic responses (weathering, nutrient mobilization, organic productivity and carbon burial). Following their arguments, positive carbon isotope trends are related to a rising sea level and negative carbon isotope trends indicate a lowering sea level. For shallow water deposits, however, deviation in carbon isotope composition away from an average seawater values are commonly attributed to diagenetic alterations of the original marine signature. Negative carbon isotopes trends are commonly believed to result from the uptake of light carbon, derived from the deterioration of organic material in soils during sub aerial exposure [37].

From the result of the isotopic analysis presented in Table 1.0 and Figure 3.0, negative

trending of the carbon isotopes of both saturated and aromatic hydrocarbons were observed. The

δ13C values for saturated hydrocarbon ranges from -28.7 to -24.1 ‰ while that of the aromatic



322


hydrocarbon component of the tar ranges from -27.53 to -23.59 ‰. This can be interpreted using

Table 2 propounded by Follimi [36]. It can therefore be argued that the source rock that produced

tar was deposited during a regressive episode.

Table 1: Result of the Carbon Isotope analysis for saturates and aromatic components of the

bitumen.

Locations ∆13C Saturates δ13C Aromatics

KDB1 -27.0 -26.4

KDB2 -26.5 -25.16

KDB3 -25.6 -24.5

UKN1 -24.6 -23.95

UKN2 -24.1 -23.64

UKN3 -24.3 -23.59

SHG1 -25.6 -24.9

SHG2 -28.6 -27.2

SHG3 -28.7 -27.53

BAI 1 -26.9 -25.87

BAI 2 -26.8 -25.7

BAI 3 -27.1 -26.92

MRP 1 -25.4 -24.67

MRP 2 -25.7 -24.82

MRP 3 -25.6 -24.68

GLK 1 -28.3 -27.2

GLK 2 -28.0 -27.21

GLK 3 -26.8 -25.7

Table 2: Correlation of Carbon Isotope Trends, Sea Level, and Stacking Patterns (Follimi et

al.[37])

δ13C Trend Sea Level Stacking Pattern

Positive Rising Transgressive systems tract; backstepping and condensed

sections downdip

Constant Stable Highstand systems tract; high organic production and

aggradation and progradation

Negative Falling Forced regression or lowstand systems tract; may not be

present updip due to exposure



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-30.0

-25.0

-20.0

-15.0

-10.0

-5.0

0.0

KDB1 KDB3 UKN2 SHG1 SHG3 BAI 2 MRP

1

MRP

3

GLK

2

Locations

Saturates

Aromatics

Fig. 3: Stable Isotope plots for different locations in the study area Carbon Isotopic Composition as a Reflection of Source

Source is the predominant factor controlling the carbon isotopic composition of oil [9-12, 20]. Enrichment in δ13C relative to δ12C is caused by the following phenomena while the reversal leads to depletion

• Rapid growth by primary producers with consequent minimization of the isotopic fractionation, accompanying photosynthetic fixation of CO2 [38] possibly associated with seasonal blooms of primary producers [39-40];

• Enhancement of salinity and high temperature, thus minimizing concentration of dissolved CO2 and decreasing isotopic fractionation

• Carbon in HCO3- is enriched in 13C relative to that in dissolved CO2 by about 9‰ at 250C.

Local phenomena are the main control on the δ13C/ δ12C ratios. Strong depletion of δ13C is common to those of lacustrine environment and its related oils i.e. environment where respired CO2 and biologically derived CH4 are efficiently recycled by biosynthetic processes.

This provides a general explanation for the δ13C values obtained for both the saturate and aromatic components of the tar (Table 1). These values signify enrichment in stable δ13C relative to δ12C (δ13C/ δ12C). A δ13C value of > -30‰ signifies enrichment while those less than -30‰ indicate depletion. Little or low enrichment in δ13C signifies little or no anoxic environment during deposition. Both saturates and aromatics components of the tar are enriched in δ13C (Saturates -28.7 to -24.1 ‰; aromatics-27.53 to -23.59 ‰). These values strongly correlate with values commonly obtained for marine organic matter. This corroborates the source as obtained on the Sofer plot (Fig. 4) to be marine. A δ13C values of < -30‰ will signify a strongly depleted organic material and this will qualify for lacustrine deposits.



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-29

-28

-27

-26

-25

-24

-23

-22

-21

-20

-30

-31 -30 -29 -28 -27 -26 -25 -24 -23 -22 -21 -20

Sofer Line (1984)

δ 13

C Saturates

13

C Aromatics

δ

Waxy (Non marine Oil)

Non Waxy (Marine Oil)

Fig. 4: Sofer Line [41] Plot, showing the source of the organic matter that generated the tar Heavy and Light Isotopes

There is no distinct variation in δ13C values obtained for both saturates and aromatics components of the tar samples to permit discrimination on the basis of their source. Although organic matter derived from marine environment are generally depleted of δ13C, Table 1 (i.e. negative δ13C values), the values obtained from the isotopic analysis can be used to discriminate the samples into two isotopic groups. These are

• Light isotopic group

• Heavy isotopic group Those samples with δ13C values of their saturates greater than -25 are said to be heavy while those with δ13C saturate values less than -25 are said to be light isotopically. The samples from UKN and MRP belong to the heavy isotope group, while samples from KDB, SHG, BAI and GLK belong to the light isotope group. Level of Biodegradation

The results obtained in are presented in table 3.0 below. From the result, the bitumen samples show variation in the API gravity values from place to place. The values range from 110 to 20.20. When these results are compared to oil classification based on the level of biodegradation by Miiller et al. [42] (Table 4) we observe that the tar deposits are moderately biodegraded. From Figure 5.0, the biodegradation trend can be observed to be more intense around the Ogun axis (BAI, and UKN) of the deposit, compared to the Ondo axis (GLK, MRP, KDB, and SHG).



325


Table 3: Result of API gravity for different localities

Location API Gravity Values (0)

Baibai Area (BAI) 11 Loore (UKN) 13.56 Goodluck Area (GLK) 18.0 Michelin Rubber Plantation (MRP) 20.0 Oke Idebi Area (KDB) 18.5 Shogbon Area (SHG) 20.2

Table 4: Levels of biodegradation in oil (modified after Miiller et al, 1987 [42])

Level API Gravity (0)

Non-degraded oil 32 Moderately-biodegraded oil 12 Heavily-biodegraded oil (Tar sand) 4

0

5

10

15

20

25

BAI UKN GLK MRP KDB SHG

Locations

API (O)

Fig. 5: A plot of API gravity values at different locations

CONCLUSION

Study area fall within the Afowo Formation, a member of the Abeokuta Group in the eastern part of Dahomey basin. Stable isotope analyses have provided a better tool in characterization of the tar sand deposits in the Southwestern Nigeria. From the isotopic and API gravity results, the



326


following conclusions were made: The bitumen contents of the tar sand were sourced from marine organic matter (Non-waxy oil type); the source bed of the bitumen was deposited in a marine environment during a regressive episode; the bitumen is moderately biodegraded and the biodegradation trend decreases from Ogun to Ondo (i.e. eastwards of the belt) axis of the deposit References 1. Klemme, H.D., (1975): Geothermal Gradients, Heatflow and Hydrocarbon Recovery. In: A.G. Fischer

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