Geochemical characteristics and reservoir continuity of Silurian Acacus in Ghadames Basin, Southern Tunisia

Accepted Manuscript Geochemical characteristics and reservoir continuity of Silurian Acacus in Ghadames Basin, Southern Tunisia

S. Mahmoudi, A. Belhaj Mohamed, M. Saidi, F. Rezgui PII:

S1464-343X(17)30139-5

DOI:

10.1016/j.jafrearsci.2017.03.023

Reference:

AES 2859

To appear in:

Journal of African Earth Sciences

Received Date:

17 November 2016

Revised Date:

15 March 2017

Accepted Date:

21 March 2017

Please cite this article as: S. Mahmoudi, A. Belhaj Mohamed, M. Saidi, F. Rezgui, Geochemical characteristics and reservoir continuity of Silurian Acacus in Ghadames Basin, Southern Tunisia, Journal of African Earth Sciences (2017), doi: 10.1016/j.jafrearsci.2017.03.023

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ACCEPTED MANUSCRIPT A study of maturity and depositional environment were perfomed with light fraction. Chromatographic data are used to study Acacus reservoir continuity. Oil-oil correlation based on GC data show the common origin of oils. Different biomarkers have been exploited in the correlation oil-source rock. The biomarker analysis shows that the oils are derived from Silurian hot shale.

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Geochemical characteristics and reservoir continuity of Silurian Acacus in Ghadames Basin, Southern Tunisia S. Mahmoudi a,b, A. Belhaj Mohamed a, M. Saidi a and F. Rezgui* b a

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Entreprise Tunisienne d’Activités Pétrolières- 54, Av. Med V, TunisTunisie b Université de Tunis El Manar, Faculté des Sciences de Tunis, Laboratoire de chimie organique Structurale LR99ES14, Campus Universitaire,2092 Tunis, Tunisie

Abstract

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The present work is dealing with the study of lateral and vertical continuity of the multi-layers Acacus reservoir (Ghadames Basin-Southern Tunisia) using the distribution of hydrocarbon fraction. For this purpose, oil–oil and source rock–oil correlations as well as the composition of the light fractions and a number of saturate and aromatic biomarkers parameters, including C35/C34 hopanes and DBT/P, have been investigated.

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Based on the ratios of light fraction and their fingerprints, the Acacus reservoir from Well1 and Well2 have found to be laterally non-connected although the hydrocarbons they contain have the same source rock. Moreover, the two oil samples from two different Acacus reservoir layers crossed by Well3A3 and A9, display a similar hydrocarbons distribution, suggesting vertical reservoir continuity.

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On the other hand, the biomarker distributions of the oils samples and source rocks assess a Silurian ‟Hot shale” that is the source rock feeding the Acacus reservoir. The biomarker distribution is characterized by high tricyclic terpanes contents compared to hopanes for the Silurian source rock and the two crude oils. This result is also confirmed by the dendrogram that precludes the Devonian source rocks as a source rock in the study area.

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Key words:

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Acacus Reservoir, Silurian ‘’Hot Shale’’, Devonian, Source rock, Light fraction, Biomarker, Reservoir continuity.

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1.

Introduction

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The light molecular hydrocarbon fraction (C4-C9) has played an increasingly important role in petroleum exploration. Over the last decade, Slentz (1981) and Kaufman (1990) have used this fraction to determine reservoir continuity. The light hydrocarbon fraction can be used to characterize source rocks facies, to determine thermal maturity as well as to indicate various reservoir alteration processes, and correlate oil to oil. In fact, Hunt (1980) proposed several parameters to evaluate the level of maturity. Three years later, Thompson (1983) developed various C6-C7 ratios and introduced the plot of the heptane versus isoheptane ratios as indicator of source, thermal maturity and biodegradation. Halpern (1995) proposed C7 ratios that can be used in star diagrams to assess reservoirs processes alteration. Mango (1987, 1990) proposed to use the light fraction in oil-oil and oil-condensate correlations. The study of biomarkers was designed to better understand the origin of crude oil samples from three wells (Fig. 1). Oil-source rock correlation is based on the concept of similarity of biomarker distribution.

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The present work deals with a Tunisian case study using oil fingerprinting technology to assess lateral and vertical continuity of Acacus reservoirs, in order to precise the origin of the Acacus reservoir oils (oil-oil and oil-source rock correlation).

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2.

Regional geology settings of Acacus reservoir

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Samples were selected from three wells located in the Ghadames basin (Southern Tunisia) (Fig.1). A structure profile of the Ghadames Basin is introduced in Fig. 2. The lithostratigraphic chart of the Tunisian part of Ghadames basin (Fig. 3) has been described by Boujema (1987), and Acheche (2001). This sedimentary basin is characterized by the presence of three major shortening phases (Taconic, Caledonian and Hercynian unconformities) separated by extensional phases (Cambrian, Silurian and Permian) (Aissaoui et al., 2016). The depositional sequence includes thick shaly series, deposited generally in suboxic environment, which are excellent oil prone source rocks (e.g Aouinet Aouinine formation and Tannezuft Hot Shale). Reservoirs levels have been identified in the Mesozoic and the Paleozoic sequences (Aissaoui et al., 2016).

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These include the Triassic TAGI (“Trias Argilo-Gréseux Inférieur”), the Devonian Tadrart formation, the Silurian Acacus formation and the upper Ordovician Jaffara formation. Oil samples, collected from the Acacus formation in three wells named Well1, Well2 and Well 3, that were used for detailed geochemical characterization.

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The term Acacus was introduced by Desio (1936) after Jabel Acacus, southwest Libya (Banerjee, 1980). The Acacus formation consists of sandstone and mudstone representing marine to marginal marine depositional environments. The Acacus sandstone is the predominant oil and gas reservoir in the Libyan and Tunisian portion of the province. The Acacus Formation can be divided into three main parts: Acacus A, Acacus B and Acacus C, or Lower Acacus, Middle Acacus and Upper Acacus, respectively. This subdivision has been based on the lithology differences between the different sequences (Bouzid, 1991).

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The Lower and Upper Acacus are predominantly sandstones and generally separated by a thick interval of about 91 to 122 m of mainly silty shale beds, namely the Middle Acacus Formation, which are easily picked up on well logs. The sandstones have fair to good petrophysical characteristics: porosity and permeability range from 10 to 28% and 40 to 125 md, respectively (Aissaoui et al., 1996). 2

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Lower Acacus: The Lower Acacus in the studied wells is mainly silty-claystone with minor sandstone with some shale alternations. The thicknesses of this formation are 214 m, 227 and 233 m, respectively on Well1, Well2 and Well3.The petroleum companies, operating in Ghadames basin, subdivide the Lower Acacus reservoirs into thin sandstone levels namely A1-A9 (Fig. 4).

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Middle Acacus: The Middle Acacus interval is predominantly a silty shale unit in which the shale is grey.

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Upper Acacus: The Upper Acacus consists mainly of white, light grey, occasionally brown sandstone, fine to very fine grained, characterized by the frequent occurrence of ferruginous sandstone at top.

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Fig.1. The location of basin Ghadames, North Africa. (b) Pre-Mesozoic subcrop map of basin Ghadames (Galeazz et al., 2009). (c) Schematic section through the Ghadames basin showing the situation of the Paleozoic series (Memmi et al., 1986 ).

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Fig. 2. Structure profile Across Ghadames basin, Southern Tunisia (Acheche, 2001).

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Fig. 3. Lithostratigraphic chart of Ghadames basin (Boudjema, 1987; Acheche, 2001)

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Fig. 4. Schematic cross section, Lower Acacus A, Oued Zar units. 3.

Devonian and Silurian source rocks

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Devonian and Silurian formations are two major source rocks that are defined as the principal source in the Ghadames petroleum system (Ghenima, 1995). In Ghadames Basin, the TOC contents of Silurian Tannezuft and Middle to Upper Devonian Aouinet Ouenine source rocks range from 0.7 to 15 % and from 0.8 to 4%, respectively.

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The values of HI, corresponding to Middle to Late Devonian source rock, rise from 70 to 547 mg HC/g TOC. Owing to that, Aouinet Aouinine formation may be considered as an excellent oil /gas prone source rock. The thermal maturity of Middle Devonian organic matter was also evaluated based on Tmax varying between 429 °C and 440 °C, indicating immature to marginally mature stage (Early oil window). A predominant suboxic marine depositional environment was indicated by biomarker parameters.

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The Silurian ‘hot shale’ is one of the potential Paleozoic source rocks extending from Morocco to Libya, in which the TOC values range from 10 to 17 %. In fact, the Silurian source rock in Morocco reachs a maximum of TOC 10.5 %, whereas, in Algeria, the values of TOC are higher than 17%. This shale basal has a maximum TOC content of 16.7 % in Libya (Lüning et al., 2003). In our area study, the thick Lower Silurian varies from 20 m to 24 m (Lüning et al., 2000). The lower Liandovery, especially the basal “hot shale unit”, exhibits high TOC reaching 15% contents and mean to high HI values higher than 200 mg HC/g TOC; their kerogen is also of a type II. Based on biomarker analysis, the hot shale fossilized a marine organic matter which deposited in anoxic to suboxic environment showing an early mature stage (oil prone).

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4.

Data and Methods

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Gas chromatographic analysis were performed using a Varian 3800 gas chromatograph with 100 m x 0.25 mm and 0.50 film thickness DB-1 capillary column. The conditions were set as follow: Injector temperature 250°C, detector temperature: 300 °C, oven column program 35 °C during 15 min, 35-300 °C at 2 °C/min and 30 min at 300 °C.

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The saturated and aromatic fractions were injected in a GC-MS an Agilent 5973 quadruple mass spectrometer that was coupled to a 7890A gas chromatograph. GC was equipped with a silica capillary column of 60 m length, 250 mm ID and 0, 25 µm film thickness. The oven temperature for the saturate fraction was programmed from 50 °C (hold time 2 min) to 170 °C at 10 °C/min to 300 (hold time 10 min) at 1.1 °C/min. The oven temperature for the aromatic fraction was programmed from 80°C to 300 °C (hold time 20 min) at 3°C/min.

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5.

Analysis of low molecular weight hydrocarbons

GC analyses of the light hydrocarbon fraction from the Acacus sandstone show that paraffinic hydrocarbons contents are absolutely predominant. These contents vary from 55% to 65% as illustrated on Fig.5 and reported in Table 1. On the other hand, the content of Naphthenic hydrocarbon (especially methylcyclopentane and 2-methylhexane) shows a slight variation between the four samples. It corresponds to 34%, 36%, 43% and 44% in well2, Well3-A3, Well3-A9 and Well1 samples, respectively. paraffinic and naphthenic hydrocarbon content distribution within the samples indicates that the shale source rocks are dominated by sapropelic organic matter (Weimin, 1987).

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Fig.5. Light fraction hydrocarbon whole composition of Acacus reservoir oils

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Table 1. Distribution of light Hydrocarbons from the studied wells Paraffinic hydrocarbons Naphthenic hydrocarbons Aromatic hydrocarbons

Well 2 65,4% 34,2% 0,5%

Well 3-A3 63,2% 36,5% 0,3%

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Well 1 55,6 % 44,1% 0,3%

Well 3-A9 57,0 % 43,0 % 0,0 %

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Thompson (1988) used the paraffinicity vs. aromaticity plot (Fig. 6.) to assess the degree of oil alteration caused by different degradation phenomena such as biodegradation, water washing, and evaporative fractionation. Plot on Fig. 6 shows that the cloud of points relative to analyzed samples falls close to “original oil”, indicating that they were not affected by any strong alteration.

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C-7 compounds are very common to determine the depositional environment of the source rock. In fact, they have many isomers that have relatively high boiling points which make them very resistible to evaporation phenomena occurring during sampling and/or sample preparation (Mango 1994). 3RP, 5RP and 6RP are used for determining depositional environment. 3RP (iso-alkanes) are abundant in lacustrine oils; 5RP (cyclopentanes) derived from a marine source and 6RP (methylcyclohexane and toluene) of a terrigenous source (ten Haven, 1996). Projected values in the diagram of Fig. 5 show that the oils were generated from a source rock that was deposited in mixed environment (predominantly marine). However, the marine origin of the Ghadames basin source rocks is a general admitted fact.

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Maturity parameters have been also assessed based on the paraffinicity parameter of Thompson (1987). The diagram of Fig. 6 shows that all oils produced from different Acacus reservoirs levels are normal mature. Source rock lithology has been determined using C7 ternary diagram (normal C7, branched C7 and cycloalkane C7) illustrated in Fig. 7. With a high percentage of C7 cycloalkane, the cloud of point relative to four samples confirms that the source rock, generating the analyzed Acacus reservoir oils, is of shaly nature.

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Most geochemical characteristics are very similar, suggesting the same source rocks for these oils. Because of overall similarities, gross composition of light fraction of the oils from different wells has the subject of the lateral and vertical continuity study.

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Fig. 6. Toluene/n-heptane vs. n-heptane/methylcyclohexane plot based Light (C7) hydrocarbon data from the Acacus oils showing the state of alteration

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Fig. 7. Ternary diagram of isoalkanes (3RP), cyclopentanes (5RP), and cyclohexanes (6RP) showing the source facies of the hydrocarbon source of the Well 1, Well 2, Well 3-a3 and Well 3- a9 oils.

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Fig. 8. Isoheptane value vs. heptane value suggesting that the analyzed oils are mature.

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Fig. 9. Ternary diagram of C7 compounds showing depositional environments oil from Well 1, Well 2, Well 3 Wells 6.

Chromatographic data and reservoirs continuity

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Oils samples from the Well1 and Well2 are paraffinic (waxy), and considered as common characteristics of marine-sourced oil. Fig. 10 and table 1 show the variation of hydrocarbons of the four oils from the various depths of the Acacus formation in Oued Zar and Cherouq.

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Well1 and Well2 oils were compared for lateral reservoirs continuity. Despite similar unimodal distribution between the two chromatograms, the polar plot of hydrocarbon relative composition of Well 1 and Well 2 (Fig. 11 and Fig. 13) shows a difference in distribution, along with a variation in the ratios. These compositions variations show the Acacus in the Well1 and Well2 are not laterally continuous.

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Based on the FID chromatograms of Well3-A3 and Well3-A9 samples, it appears that they have not experienced any biodegradation and they have the same maturity level (Fig. 12 and Fig. 14). The levels A3 and A9 in of Well 3 are compared for vertical reservoirs continuity. The polar plot constructed on the basis of several hydrocarbon ratios (Fig. 14. and Table 2) of Well 3-A3 and Well 3-A9 oils, shows extremely similar distribution, suggesting vertical reservoirs continuity. This result put in evidence the assumption that the shaly dominated levels separating the sandy ones (A3, A5, A7, A8, and A9) are not completely impervious.

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Table 2. Hydrocarbon peak ratios relative to Well1, Well2 and Well3 oils used for evaluating the reservoirs continuity Oil samples Well 3 -A3 Well 3 - A9 Well 1 Well 2

a/b 0,2 0,3 1,0 0,6

c/d 2,0 4,8 1,5 1,0

e/f 0,7 0,5 1,5 0,6

f/g 0,8 1,0 1,1 1,2

h/i 0,7 0,7 0,8 0,7

j/k 1,3 1,3 0,9 0,9

l/m 0,9 0,9 2,0 2,6

9

n/o 0,6 0,6 1,1 2,3

p/q 2,6 2,5 1,2 3,9

r/s 2,6 3,0 0,8 0,8

A/B 1,7 1,6 0,9 1,6

C/D 1,2 1,0 0,9 1,0

E/F 1,5 1,4 1,0 1,0

G/H 0,6 0,7 0,8 0,7

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Fig. 10. FID Gas chromatograms of crude oils from Acacus Formation in Well 1, Well 2 and Well 3 (levels: a9 and a3).

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Table 3. Chemical identification of branched and cyclic compounds used to evaluate reservoir continuity Peak

Chemical name

Peak

a

n-Propylcyclohexane

j

b

2-Methylnonane (C10 isoalkane)

k

c

3-Methylnonane (C10 anteisoalkane)

l

d

2,6-Dimethylnonane (C11 isopronoid)

e

Chemical name

Peak

Chemical name

s

2-Methylpentadecane (C 16 isoalkane)

A

n-Undecyleyelohexane 5-methylheptadecane

2,6,10-Trimethyldodecan (Farnesane, C15 isoprenoid)

B

2-Methylheptadecane (C18 isoalkane)

m

C5-Substituted decaline

C

n-Pentylcyelohexane + 1-Methyl deealine

n

5-Methyltetradecane

D

f

2-Methylundecane (C 12 isoalkane)

o

4-Methyltetradecane

E

g

3-Methylundecane (12- isoalkane)

p

2,6,10 Trimethyltridecane

F

h

4-Methyldodecane

q

-----------------------

G

i

2-Methyldodecane

r

n-Nonylcyclohexan+7- + 6methylpentadecane (C16 isoalkane)

H

3- Methyldodecane anteisoalkane)

(C13

2,6,10-Trimethylundecane

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2-Methyleicosane (C21 isoalkane 2, 6, 10, 14Tetramethylnonadecane (C23 isopronoid) 2-Methylheneicosane (C22 isoalkane) 2, 6, 10, 14, 18Pentamethylnonadecane (C24isoprenoid) Pentamethyldocosane (C27 isoprenoid) 2-Methyltetracosane

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Fig. 11. Numbered peaks of linear, cyclic and branched alkanes in the whole oil GC of Well 1and Well 2 wells: [(A) C9~C16 (B) ) C17~C25].

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Fig. 12. Numbered peaks of linear, cyclic and branched alkanes in the whole oil GC of well Well 3

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[(C) C9~C16 (D) ) C17~C25].

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Fig. 13. Polar plot of selected peak ratios from high resolution FID-GC fingerprinting of Well 1and Well2 oil samples from Acacus reservoir, showing segregation of Acacus reservoirs.

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Fig. 14. Polar plot of selected peak ratios from high resolution FID-GC fingerprinting of Well 3 oil samples from Acacus reservoir, showing apparent vertical continuity in Acacus reservoir levels.

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7.

Oil-oil correlation

The oil-oil correlation is illustrated in Fig.13. Based on some ratios which are not affected by sampling conditions, migration of oil and a long time for analysis, we have observed that oils from Well1, Well2 and Well3 produced from different stratigraphic levels, show an extremely overlap with a very small variation observed in the ratio iC5/nC5 for the fours oils, indicating a good correlation. This result indicates that these four oils come from the same source rocks (Fig. 15.).

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Fig. 15. Comparison of the high ratios of light hydrocarbon in the analyzed crude oils

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Table 4. The high ratios of light hydrocarbon in crude oils. iC4/nC4 iC5/nC5 2MC5/3MC5 nC6/(MCyC5+2,2-2-MC5) B/CyC6 CyC6/MCyC5 MB/MCyC6

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8.

Well 2 0,22 0,74 1,62 1,05 0,07 0,85 0,20

Welll 3-a3 0,22 0,80 1,63 0,94 0,03 0,83 0,06

Well 1 0,26 0,93 1,59 0,95 0,03 0,88 0,08

Welll 3-a9 0,22 0,47 1,54 1,01 0,03 0,82 0,11

Oil-source rock correlation

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After migration, some parameters can affect the light hydrocarbon composition like absorption and microorganism activity. For this reason, oil source rock correlation can be made on the basis of the data on biomarkers.

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The most powerful argument for the proposed source rock –oils correlation come from sterane and triterpane distributions. The distribution of the crude oil Well3-A9 and Well2 are quite similar to the distribution of Tannezuft hot shale Source rock (Fig. 16.).This distribution characterized by the high content of terpanes reflecting the similarities in thermal maturity and lithofacies. On the other hand, the two oils seep Well2 and Well3- A9 chromatogram show a difference in a source parameters and lithology

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with the Devonian source rock (Table 3). Fig. 15 shows that that the crude oils are poorly correlated with the Devonian source rock (EC) but are well correlated with hot shale Tannezuft formation.

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Fig. 16. Dendrogram, based on biomarkers ratios, showing the relationship between Well 3-A9 and Well 2 oil samples from Lower Acacus and two source rock extracts from the Silurian hot shale and Devonian source rock.

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Fig. 17. Comparison of n-alkanes (m/z 85) and terpanes (m/z 191) distributions of Well 3-A9 and Well 2 oils and both the Silurian (Tannezuft) and Devonian (Aouinet Ouenine) source rocks.

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9.

Conclusion

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A detailed analysis of light fractions and biomarker compositions of oils from Acacus reservoir in the Basin Ghadames, Southern Tunisia, was performed.

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All the oils are derived from kerogen Type II of a marine source rock. Based on our data, the optimal parameters to assess maturity are heptane and isohopane values. The correlation between the two parameters shows that the four oils reached the early mature stage.

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On the basis of light fractions distributions and biomarkers compositions of different oils, we have shown that these latter were deported from the common source rock, which is dominantly argillaceous and was deposited in suboxic conditions. Moreover, Oil source correlations indicated that the oils in the Acacus reservoir rock are derived from the Lower Silurian (hot shale) source rock.

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Acknowledgment

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We want to thank ETAP for permitting us to publish this paper.

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