Biological Marker Fingerprints of Crude Oils from Three Oilfields in the Central Niger Delta: Implication to Source Input, Conditions of Deposition, and Thermal Maturation

GeoScience Engineering Vol. 68 (2022), No. 2 geoscience.cz pp. 134–150, ISSN 1802-5420 DOI 10.35180/gse-2022-0076 BIOLOGICAL MARKER FINGERPRINTS OF CRUDE OILS FROM THREE OILFIELDS IN THE CENTRAL NIGER DELTA: IMPLICATION TO SOURCE INPUT, CONDITIONS OF DEPOSITION, AND THERMAL MATURATION Timothy Chibuike ANYANWU1 , Ifeoma Ogeri AGBI2 , Botwe TAKYI3 , Joy Obiageli NJOKU1 , Uduak Anthony UGBAJA4 1 Federal University of Technology Owerri, Department of Geology, Nigeria 2 Alex Ekwueme Federal University Ndufu-Alike, Department of Geology and Geophysics, Abakaliki, Nigeria 3 University of Mines and Technology, School of Petroleum Studies, Department of Petroleum Geosciences and Engineering, Tarkwa, Ghana 4 University of Calabar, Department of Pure and Applied Chemistry, Calabar, Nigeria E-mail: [email protected] ABSTRACT Crude oil samples recovered from three oilfields distributed within the central Niger Delta were used to investigate biological marker fingerprints, sources of organic matter, conditions of deposition, and thermal maturation. This was achieved by the application of gas chromatography-mass spectrometric (GC-MS) analyses on the saturated components of the crude oils. The biological marker ratios show low sterane/hopane (steranes/hopane ˂ 1) in the scope of 0.29 to 0.61 indicating that the crude oils initiated from rocks containing high terrigenous biota (mainly land plants). The n-alkanes distribution and the pristane/phytane ratios (0.63 to 2.08) suggested source deposition under oxic to suboxic environmental conditions. The percentage composition of C27, C28, and C29 steranes and oleanane index (18α (H)-oleanane/ C30 17α (H)-hopane) also indicated major contributions from terrigenous organic biota with minor marine source input. The studied crude oils have C32:22S/ (22S+22R) ratios in the scope of 0.55 to 0.64, and these values suggested high maturation level. This agrees with the oleanane index (0.64 to 0.95), CPI (0.92 to 1.06), C29: 20S/ (20S + 20R) sterane ratios (0.29 to 0. 61), Ts/(Ts+Tm) ratio (0.45 to 0.83) and moretane/C30 hopane proportion (0.16 to 0.24). Keywords: Biological marker; Depositional conditions; Niger Delta; Organic matter; Thermal maturation. 1 INTRODUCTION The Niger Delta Province is characterized by synsedimentary fault systems, which subdivided the Delta into five distinct sedimentation cycles of fluviomarine systems referred to as depobelts (Fig. 1). These depobelts (depocenters) represent successive growth stages and are self-contained, as regards to their structural framework and hydrocarbon distribution [1–3]. The stratigraphy of the Niger Delta is made up of an upper delta top lithofacies known as the Benin Formation, which is composed of continental sands and gravels of about 2000m thickness [4]. Benin Formation is underlain in a gradational fashion by the delta front paralic facies of the Agbada Formation (Fig. 2). The Agbada Formation is comprised of mostly sands with little shales in the topmost parts, and a succession of equal proportions of sands and shale in the lower units [5, 6]. This Formation is regarded as the true deltaic portion that bears the major petroleum horizons in the Niger Delta. The Pro-delta marine shales of the Akata Formation are found occurring at the base of the delta and are made up of thick sequences of shale referred to as the potential source rocks (Fig. 2) [5, 6]. 135 GeoScience Engineering Vol. 68 (2022), No. 2 geoscience.cz pp. 134–150, ISSN 1802-5420 DOI 10.35180/gse-2022-0076 Biological markers are complex organic molecules found in crude oils, sediments, and rocks [7–9]. They are molecular remnants of primitive life forms, having the same structural arrangement as their precursor organisms [9]. Biological markers are commonly referred to as biomarkers and may exist as remains of proteins, lipids, carbohydrates, nucleic acids, and other molecules. They are very useful because their complex structures are not usually different from their similar organic molecules present in living organisms [9]. Most biological markers are restricted to particular sources, easily analyzed from environmental and geologic samples, and are not compliant to geochemical alteration. Therefore, biomarkers can be used as proxies in recent environments and as chemical guide fossils. The occurrences and distribution patterns of biological markers such as the hopanes and steranes in crude oils can be used to investigate generic relationships among crude oils, oil source rock relationship, depositional environments, and thermal maturity which are useful exploration indices [9]. The geochemical attributes of the Niger Delta crude oils and source rocks have been discussed in previous studies [10–12]. Bustin [11] concluded that the Niger Delta hydrocarbons belong to one family, originating from land plants (terrestrial organic materials) and other organic matters of undetermined structure. A study carried out by Ekpo et al. [13] recognized that crude oils from oilfields in the western offshore Niger Delta were source related and deposited under oxidizing conditions. Onojake et al. [14] indicated that oil samples from two oilfields located in the Niger Delta were sourced from terrestrial biotas deposited under an oxic environment. Similarly, Oforka et al. [15] opined that crude oil samples from the southwest Niger Delta had derived from terrestrial organic materials and deposited under oxic paleoenvironmental conditions. Akinlua and Ajayi [16] recognized that oil samples from some fields in the central part of the Niger Delta are thermally matured having source organic matter contributions from a mixture of terrigenous and marine, deposited in oxidizing environments. Sonibare et al. [17] indicated mixed organic matter input (both marine and terrestrial kerogen) for crude oil samples from onshore and offshore Niger Delta. Abrakasa and Muhammad [18] recognized the existence of a close geochemical relationship and thermal maturity gradient trend in the Southwest-Northeast direction for crude oils from an oilfield in the Niger Delta. Manilla and Eking [19] concluded that the Nigerian crude oils are of two different families of terrestrial and mixed (terrestrial and marine) petroleum systems. Anyanwu et al. [20] identified subtle geochemical dissimilarities among oil samples from the coastal and offshore Niger Delta. Onojake and Abrakasa [21] applied the presence of 18α (H)-oleanane skeletons and oleanane indices to indicate terrestrial source and Tertiary age for some crude oils from the Niger Delta. Anyanwu et al. [22] used biomarker fingerprints from the five depocentres of the Niger Delta to identify a single family of oil originating from source rocks with major input from terrestrial biotas deposited in a prevailing condition of oxic to sub-oxic environment. Knowledge of the source input, conditions of deposition, and thermal maturation of oils and source rocks in a hydrocarbon producing basin are very useful in reservoir engineering and petroleum exploration. Most of the geochemical studies carried out in the Niger Delta suggested one petroleum system [10, 22, 23, 24, 25], with organic materials originating mostly from terrigenous land plants and other organic matters of undetermined structure [11, 21, 22]. A study of the geochemical characters of oil from the different segments of the Niger Delta is very important in order to ascertain if there are slight differences in the petroleum systems within the different units of the delta. This work attempts to investigate the organic geochemical fingerprints of crude oil samples recovered from three oil fields within the Central Niger Delta in order to characterize the crude oils and determine the organic matter source (s), depositional conditions, and thermal maturation. The study area (Niger Delta) is a major hydrocarbon zone in Africa located in the Gulf of Guinea, West Africa in-between latitude 3°N to 6°N and longitude 5°E to 8°E (Fig. 1). 136 GeoScience Engineering Vol. 68 (2022), No. 2 geoscience.cz pp. 134–150, ISSN 1802-5420 DOI 10.35180/gse-2022-0076 Figure 1. Location of the study area: A. A general geologic map of the Gulf of Guinea and surrounding areas [26]; B. Map of the Niger Delta showing the location of depobelts (location map of Nigeria in inset box); open squares show the locations of the three oilfields where the crude oil samples were collected [27] 137 GeoScience Engineering Vol. 68 (2022), No. 2 geoscience.cz pp. 134–150, ISSN 1802-5420 DOI 10.35180/gse-2022-0076 Figure 2. Stratigraphic column displaying the three formations of the Niger Delta; Fm = formation [6] 2 MATERIALS AND METHODS Five crude oil samples (S1, S2, S3, S4, and S5) were collected from three oil producing fields (A, B, C) (Fig. 1). The crude oil samples are representatives from the Central Swamp depobelt comprising an alternation of equal proportions of sands and shale of the Eocene to Recent Agbada Formation, regarded as the true deltaic portion and 138 GeoScience Engineering Vol. 68 (2022), No. 2 geoscience.cz pp. 134–150, ISSN 1802-5420 DOI 10.35180/gse-2022-0076 the major hydrocarbon horizon. The fractionation of the oil samples into saturates components, aromatic components, and hetero-compounds were done by liquid-chromatography using silica-gel promoted with alumina: n-hexane was used for elution of saturated hydrocarbons, aromatic fractions were eluted using dichloromethane and 1, 2 methanol-dichloromethane was used to elute the hetero-compounds. Gas chromatographic-mass spectrometric (GC-MS) analyses were carried out with the aid of the Agilent’s 7890 gas chromatography attached with an Agilent’s HP-5 ms column. The oven operating conditions were held at 55 °C for 1 minute, programmed from 25 °C min-1 to 320 °C, and held for 35 minutes. The carrying gas was helium (He), and placed at a continuous flow. The SI Scan monitoring mode was used, and GC operations were made at an electron ionization (EI) mode of 70 eV. Data processing was carried out using Chemstation G1701BA, peaks integration was by RTE integrator. Identifications of peaks were done by considering the retention time, comparing with set standards, mass fragmentation patterns, and literature. The cumulated peak area of each compound was used for the computation of ratios. 3 RESULTS AND DISCUSSION 3.1 Organic matter source(s) and depositional conditions 3.1.1 Normal-alkanes Certain n-alkanes ratios are useful indicators of organic matter sources [9]. The n-alkanes distribution in the crude oil samples is shown on the (71m/z ion) mass chromatograms (Fig. 3). The mass chromatograms show an abundance of n-alkanes in the range of n-C15 to n-C20 with a low concentration of heavy n-alkanes for crude oils from the A and B oilfields and moderately to low concentration for oil samples from C oilfield. The n-alkanes distribution in the crude oil samples from A and B oilfields suggests input from marine organic matters of algal and planktonic origin whereas crude oil samples from C oilfield suggests mixed input from both marine and terrigenous organic materials [12, 28]. Low concentrations to the absence of normal alkanes in the range of n-C6 to n-C12 observed in the mass chromatograms as well as the non-uniformity in the distribution patterns suggests crude oil biodegradation and possible different genetic histories for the crude oils [9]. The degree of waxiness of oils was determined in this study using the ratio Σ (n-C21n-C31)/Σ (n-C15 - n-C20) [29] (Table 1). This idea is based on the proposition that terrestrial organic materials contribute the most to high molecular weight n-alkanes in crude oil [30]. It was used to describe the origin of organic materials in the source rock from where the studied crude oils were expelled. Crude oil samples from A (S1) and B (S2, S3) oilfields contains low waxy oil ratios (waxiness ˂1) while the crude oil samples from C oilfield (S4, S5) contain waxy oil ratios that are relatively high (waxiness >1) (Table 1). This suggested high concentrations of terrigenous organic materials derived from land plants for the crude oil samples from “C” oilfield and a relatively lower concentration for the crude oils from A (S1) and B (S2, S3) oilfields. The computed carbon preference index (CPI) for the analysed crude oil from A (S1) oilfield is 0.92 while those of B (S2, S3) and C (S4, S5) oilfields range from 1.01 to 1.06 (Table 1), this range of values showing no odd or even number carbon preference suggested matured crude oils [31]. 3.1.2 Acyclic isoprenoids ratio (Pristane/phytane) The Acyclic isoprenoids: pristine (Pr) and phytane (Ph) originates from the phytol which is a side chain of chlorophyll. Ph is derived during reducing conditions while the Pr is produced under oxidizing conditions [32]. The Pr/Ph ratio is among the most important indicators of environments of deposition [9], where Pr/Ph ratios less than one indicate crude oils sources from reducing environments. High Pr/Ph ratios (Pr/Ph˃ 3) normally indicate an oxic-terrestrial source rock depositional environment, while Pr/Ph ratios in the range of 1.00 to 3.00 reflects oxic environmental conditions of deposition [9, 33]. The crude oil samples from A (S1) and B (S2, S3) oilfields had Pr/Ph ratios of 2.08 and 0.982.01 respectively, while crude oils from C (S4, S5) oilfield had Pr/Ph ratios of the range 0.63 to 0.65 (Table 1). This shows that the crude oils from A (S1) and B (S2, S3) oilfields were sourced from terrestrial organic matter or mixed organic matter sources, deposited under oxic conditions while those from C (S4, S5) oilfield were probably sourced from marine organic matter deposited in a suboxic environmental condition [9, 33, 34]. Moreover, the cross plot of CPI versus Pristine/Phytane shows that the crude oils from A 139 GeoScience Engineering Vol. 68 (2022), No. 2 geoscience.cz pp. 134–150, ISSN 1802-5420 DOI 10.35180/gse-2022-0076 (S1) and B (S2, S3) oilfields fall within the field of more oxidizing environment while those of C (S4, S5) oilfield fall in the region of more reducing environment (Fig. 4). Figure 3. Typical mass chromatograms (71 m/z ion) of the saturated hydrocarbons of crude oils from the Central Niger Delta: Pr = pristine and Ph = phytane 140 GeoScience Engineering Vol. 68 (2022), No. 2 geoscience.cz pp. 134–150, ISSN 1802-5420 DOI 10.35180/gse-2022-0076 Table 1. Biological marker parameters derived from GC–MS analyses of the saturated hydrocarbon fractions of crude oils from the central Niger Delta, Nigeria A-Oilfield B-Oilfield C-Oilfield Parameters S1 S2 S3 S4 S5 Pr/Ph 2.08 0.98 2.01 0.65 0.63 Pr/n-C17 0.90 1.08 0.89 0.51 0.50 Ph/n-C18 1.20 0.41 1.22 2.60 2.59 CPI 0.92 1.06 1.03 1.02 1.01 Wax. Index 0.05 0.37 0.09 1.40 1.41 28/C29 Ster. 0.52 0.56 0.53 0.62 0.76 C29/C27 Ster. 1.01 3.78 1.03 1.00 1.19 %C29 Ster. 39.90 54.81 40.11 38.16 38.40 %C28 Star 20.71 30.68 19.61 23.73 29.22 %C27 Star 39.38 14.51 39.37 38.11 32.39 C29: 20S/(20S+20R) 0.29 0.44 0.41 0.61 0.46 Ster./Hop 0.16 0.15 0.19 0.20 0.36 Ts/(Ts+Tm) 0.45 0.47 0.48 0.83 0.50 Ts/Tm 0.81 0.88 0.82 4.78 0.99 Olea. Index 0.91 0.89 0.93 0.95 0.64 C31HH/C30H 0.32 0.33 0.35 0.34 0.39 Mor./C30Hop 0.16 0.17 0.16 0.19 0.24 C29H/C30H 0.08 0.56 0.12 0.61 0.50 C29Ts/[C29Hop + C29Ts] 0.90 0.10 0.89 0.12 0.10 C32H: 22S/(22S + 22R) 0.57 0.64 0.55 0.57 0.57 *Pr – Pristanes, *Ph – Phytanes *Pr / (Pr + Ph) – Pristines / (Pristines + Phytanes) *C29: 20S/ (20s+20R) - C29 αα 20S/ (C29 αα 20S + C29 αα 20R) *Oleananes index (Olea. Index) - α-oleananes/ C30 17α (H)-hopanes *CPI – Carbon Preferences Indices = Odd number n-alkanes/even number n-alkanes [35]. *Waxiness Index (Wax. Index) – Σ (n-C21n-C31)/Σ (n-C15 - n-C20) Ts/(Ts+Tm): 18α(H)-trisnorhopanes /(18α(H)-trisnorhopanes +17α(H)-trisnorhopanes) Ts/Tm: 18α (H)-trisnorhopanes/17α (H)-trisnorhopanes C31H/C30HC31-17a (H), 21b (H)-30 homohopanes (22S+22R)/2/ (C30 17α (H)-hopanes) Mor. / C30HopC30-17b (H), 21a (H)-moretanes / C30 17α (H)-hopanes C29/C30HC29 Tm 17a (H) 21b (H)-norhopanes / C30 17α (H)-hopanes C29Ts/ [C29Hop + C29Ts] – C29-18a (H) norneohopanes (29Ts) / (C29 Tm 17a (H) 21b (H)-norhopanes + C29-18a (H) norneohopanes (29Ts)) *C32H: 22S/ (22S + 22R) – C32-17a (H), 21b (H)-30 bishomohopanes (22S)/ (C32-17a (H), 21b (H)-30 bishomohopanes (22S) + C32-17a (H), 21b (H)-30 bishomohopanes (22R) *Ster. / Hop. – Regular Steranes /17α-hopanes *Ster: Steranes *Hop: Hopanes 141 GeoScience Engineering Vol. 68 (2022), No. 2 geoscience.cz pp. 134–150, ISSN 1802-5420 DOI 10.35180/gse-2022-0076 Figure 4. Plot of CPI versus Pristine/Phytane of the studied crude oils from the Central Niger Delta indicating a more oxidizing environment for A (S1) and B (S2, S3) oilfields and more reducing environment for C (S4, S5) oilfield 3.1.3 Isopreniods/n-alkanes The isopreniods/n-alkanes relationships (Pr/n-C17 and Ph/n-C18) are used to obtain information on depositional environmental conditions, thermal maturation, organic matter sources, digenetic conditions, and crude oil biodegradation [33]. An increase in thermal maturation leads to an increased rate of n-alkanes generation and a reduction in isoprenoids, the reverse occurs during biodegradation [36]. The Pr/n-C17 and Ph/n-C18 ratios for A (S1) oilfield are 0.90 and 1.20 respectively; Pr/n-C17 and Ph/n-C18 ratios for B oilfield are 1.08 and 0.41 (S2), 0.89 and 1,22 (S3) respectively; Pr/n-C17 and Ph/n-C18 ratios for C (S4, S5) oilfield are 0.51 and 2.60 (S4), 0.50 and 2.59 (S5) respectively (Table 1). These ratios suggest mixed source input from both marine terrestrial organic matter of mainly algae and land plants [9]. Moreover, the cross plot of Pr/n-C17 versus Ph/n-C18 indicates Terrigenous “Type III kerogen” and Marine algal “Type II kerogen” source deposition under oxygenated to suboxygenated and reducing environmental conditions with an increasing thermal maturation level [37] (Fig. 5). Figure 5. Plot of Pr/n-C17 vs. Ph/n-C18 indicating terrigenous “Type III kerogen” and marine algal “Type II kerogen” and source deposition under oxic, suboxic to reducing environments with an increasing thermal maturation level [37] 142 GeoScience Engineering Vol. 68 (2022), No. 2 geoscience.cz pp. 134–150, ISSN 1802-5420 DOI 10.35180/gse-2022-0076 3.1.4 Sterane biomarkers The sterane biomarker fingerprints were recognized on m/z 217+218 fragmentograms of the studied crude oils (Fig 6). Table 2 shows the identification of chromatographic peaks on m/z 217+218 ions (steranes) and m/z 191 ions (hopanes). The comparative distribution of C27–C29 steranes is indicative of the differences in source biogenic input [38]. The percentage abundances of C27, C28 and C29 regular steranes show that the studied crude oil from Aoilfield (S1) had nearly equal proportion of C29 (39.90%) and C27 (39.38%) compared to C28 (20.71%) regular steranes; similarly, crude oil samples from B-oilfield (S2, S3) had a high proportion of C29 (40.11%–54.81%) compared to C27 (14.51%–39.37%) and C28 (19.61%–30.68%) regular steranes while crude oils from C-oilfield (S4, S5) had a nearly equal proportion of C29 (38.16%-38.40%) and C27 (32.39%–38.11%) and lower C28 (23.73%– 29.22%) regular steranes (Table 1). The C27 to C29 steranes distribution is demonstrated using the ternary plot of Huang and Meinschein [39]. According to Huang and Meinschein’s [39] classification, higher abundances of C27 regular steranes indicate a strong marine algal input, while higher C29 regular steranes indicate a strong terrestrial influence and organic matter input from land plants. Inferences from this ternary diagram classification (Fig. 7), show that the studied crude oil samples were deposited in a mixed environment of both marine and land influences, with major organic materials from marine planktonic and flowering land plants. Figure 6. Typical mass chromatograms (217+218 m/z ion) showing steranes distribution in the crude oil samples from the Central Niger Delta 149 GeoScience Engineering Vol. 68 (2022), No. 2 geoscience.cz pp. 134–150, ISSN 1802-5420 DOI 10.35180/gse-2022-0076 [29] EL DIASTY, W.S. and J.M. MOLDOWAN. Application of biological markers in the recognition of the geochemical characteristics of some crude oils from Abu Gharadig Basin, north Western Desert – Egypt. Marine and Petroleum Geology. 2012, vol. 35(1), pp. 28–40. ISSN 0264-8172. DOI: 10.1016/j.marpetgeo.2012.03.001 [30] HEDBERG, H. D. Significance of High-Wax Oils with Respect to Genesis of Petroleum. American Association of Petroleum Geologists Bulletin. 1968, vol. 52(5), pp. 736–750. DOI: 10.1306/5D25C45B16C1-11D7-8645000102C1865D [31] TISSOT, B. P. and D.H. WELTE. Petroleum Formation and Occurrence. New York: Springer Verlag, 1984. ISBN 9780387132815. [32] MOUSTAFA, Y.M. Environmental Assessment of Petroleum Contamination of Gamasa-Damiette Beaches. Oriental Journal of Chemistry. 2004, vol. 20(2), pp. 219–226. Available at: http://www.orientjchem.org/?p=18462 [33] HUNT, J.M. Petroleum Geochemistry and Geology. 2nd edition. New York: W.H. Freeman & Co, 1996. ISBN 0-7167-2441-3. [34] TEN HAVEN, H.L., J.W. DE LEEUW, J. RULLKÖTTER and J.S. SINNINGHE DAMSTÉ. Restricted utility of the pristane/phytane ratio as a palaeoenvironmental indicator. Nature. 1987, vol. 330, pp. 641–643. ISSN 0028-0836. DOI: 10.1038/330641a0 [35] BRAY, E.E. and E.D. EVANS. Distribution of n-paraffins as a clue to recognition of source beds. Geochimica et Cosmochimica Acta. 1961, vol. 22(1), pp. 2–15. ISSN 0016-7037. DOI: 10.1016/00167037(61)90069-2 [36] WAPLES, D.W. Geochemistry in Petroleum Exploration. Boston: International Human Resources Development Corporation, 1985. Tertiary Level Biology. ISBN 9789027720863. [37] PETERS, K.E., T.H. FRASER, W. AMRIS, B. RUSTANTO and E. HERMANTO. Geochemistry of Crude Oils from Eastern Indonesia. American Association of Petroleum Geologists Bulletin. 1999, vol. 83(12), pp. 1927–1942. DOI: 10.1306/E4FD4643-1732-11D7-8645000102C1865D [38] LIJMBACH, G.W.M. On the origin of petroleum. In: Proceedings of the 9th World Petroleum Congress: May 11–16, 1975, Tokyo, Japan. London: Applied Science, 1976, vol. 2, pp. 357–369. [39] HUANG, W.Y. and W.G. MEINSCHEIN. Sterols as ecological indicators. Geochimica et Cosmochimica Acta. 1979, vol. 43(5), pp. 739–745. ISSN 0016-7037. DOI: 10.1016/0016-7037(79)90257-6 [40] PETERS, K.E. and J.M. MOLDOWAN. The Biomarker Guide: Interpreting Molecular Fossils in Petroleum and Ancient Sediments. Prentice Hall, 1993. ISBN 9780130867520. [41] MOLDOWAN, J.M., W.K. SEIFERT and E.J. GALLEGOS. Relationship Between Petroleum Composition and Depositional Environment of Petroleum Source Rocks. American Association of Petroleum Geologists Bulletin. 1985, vol. 69(8), pp. 1255–1268. DOI: 10.1306/AD462BC8-16F7-11D7-8645000102C1865D [42] GRANTHAM, P. J. and L.L. WAKEFIELD. Variations in the sterane carbon number distributions of marine source rock derived crude oils through geological time. Organic Geochemistry. 1988, vol. 12(1), pp. 61–73. ISSN 0146-6380. DOI: 10.1016/0146-6380(88)90115-5 [43] PETERS, K.E., J.M. MOLDOWAN and P. SUNDARARAMAN. Effects of hydrous pyrolysis on biomarker thermal maturity parameters: Monterey Phosphatic and Siliceous Members. Organic Geochemistry. 1990, vol. 15(3), pp. 249–265. ISSN 0146-6380. DOI: 10.1016/0146-6380(90)90003-I [44] EL-SABAGH, S.M., M.A. EBIAD, A.M. RASHAD, A.Y. EL-NAGGAR, I.H.A. BADR, M.M. EL NADY and E.S. ABDULLAH. Characterization Based on Biomarkers Distribution of Some Crude Oils in Gulf of Suez Area – Egypt. Journal of Materials and Environmental Sciences. 2017, vol. 8(10), pp. 3433–3447. ISSN 2028-2508. Available at: https://www.jmaterenvironsci.com/Document/vol8/vol8_N10/262-JMES-2622El%20Sabagh.pdf [45] OURISSON, G., P. ALBRECHT and M. ROHMER. The Microbial Origin of Fossil Fuels. Scientific American. 1984, vol. 251(2), pp. 44–51. ISSN 0036-8733. Available at: https://www.jstor.org/stable/24969433 [46] GRANTHAM, P.J., J. POSTHUMA and A. BAAK. Triterpanes in a number of Far Eastern crude oils. In: BJORØY, M., C. ALBRECHT, C. CORNFORD et al. (eds.). Advances in Organic Geochemistry 1981. New York: John Wiley & Sons, 1983, pp. 675–83. [47] TEN HAVEN, H.L. and J. RULLKÖTTER. The diagenetic fate of taraxer-14-ene and oleanene isomers. Geochimica et Cosmochimica Acta. 1988, vol. 52(10), pp. 2543–2548. ISSN 0016-7037. DOI: 10.1016/00167037(88)90312-2 [48] WHITEHEAD, E.V. The Structure of Petroleum Pentacyclanes. In: TISSOT, B. and F. BIENNER. Advances in Organic Geochemistry 1973: Proceedings of the 6th International Meeting on Organic Geochemistry: September 18–21, 1973, Rueil-Malmaison, Paris, France. Paris: Technip, 1974, s. 225–243. ISBN 9782710802587. 150 GeoScience Engineering Vol. 68 (2022), No. 2 geoscience.cz pp. 134–150, ISSN 1802-5420 DOI 10.35180/gse-2022-0076 [49] UDO, O.T. and C.M. EKWEOZOR. Significance of oleanane occurrence in shales of Opuama Channel Complex, Niger Delta. Energy & Fuels. 1990, vol. 4(3), pp. 248–254. ISSN 0887-0624. DOI: 10.1021/ef00021a006 [50] OGBESEJANA, A.B., O.O. SONIBARE and Z. NINGNING. Occurrence and Distribution of Pyrene and its Derivatives in Crude Oils and Source Rock Extracts from Niger Delta, Nigeria. Journal of Petroleum Science and Technology. 2019, vol. 9(2), pp. 3–17. ISSN 0920-4105. DOI: 10.22078/JPST.2018.3271.1521 [51] MOLDOWAN, J.M., P. SUNDARARAMAN and M. SCHOELL. Sensitivity of biomarker properties to depositional environment and/or source input in the Lower Toarcian of SW-Germany. Organic Geochemistry. 1986, vol. 10(4–6), pp. 915–926. ISSN 0146-6380. DOI: 10.1016/S0146-6380(86)80029-8 [52] EL-SABAGH, S.M., A.Y. EL-NAGGAR, M.M. EL NADY, M.A. EBIAD, A.M. RASHAD and E.S. ABDULLAH. Distribution of triterpanes and steranes biomarkers as indication of organic matters input and depositional environments of crude oils of oilfields in Gulf of Suez, Egypt. Egyptian Journal of Petroleum. 2018, vol. 27(4), pp. 969–977. ISSN 1110-0621. DOI: 10.1016/j.ejpe.2018.02.005