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Abstract

The Bongor Basin is a typical lacustrine passive-rifted basin situated in the West and Central African Rift System (WCARS). It has experienced two phases of tectonic inversion and features a complex process of petroleum generation and accumulation. A total of 41 crude oil samples from the basin were geochemically analyzed to investigate their compositions of molecular markers. The results show that the oils have similar origins and are likely to belong to the same oil population. However, there are significant differences in geochemical characteristics and physical properties, caused by the secondary alteration. The relative contents and distribution patterns of normal alkanes and acyclic isoprenoids indicate that some of the oils have suffered biodegradation to varying degrees. The samples can be divided into three categories according to their relative degrees of degradation: normal oil, slightly biodegraded oil (PM 1–3), and severely biodegraded oil (PM 5–7). The burial depth of oil reservoirs in this area is the predominant factor impacting on the level of biodegradation. Crude oils in reservoirs with burial depths of less than 800 m are all severely biodegraded, while oils in reservoirs with burial depths greater than 1300 m have experienced no evident biodegradation. In reservoirs with burial depths between 800 m and 1300 m, the biodegradation degrees vary from normal to severely biodegraded. Oil reservoirs with burial depths less than 1300 m and adjacent to major faults are readily subject to biodegradation, while reservoirs with similar burial depths, but a certain distance away from major faults, have suffered no evident biodegradation. Moreover, if primary reservoirs have been modified by tectonic activity after accumulation, the crude oils are more likely to be biodegraded. Faulted anticline traps may create more favorable geological conditions for preservation of crude oil than reverse extrusion anticline reservoirs. This study may provide practical guidance for the assessment and prediction of oil quality in future oil exploration.

Keywords

geochemical characteristics biodegraded oil hydrocarbon exploration bongor basin tectonic inversion

Introduction

The physical properties and chemical compositions of crude oils in reservoirs are principally controlled by their origins, and the thermal maturity of the organic matter, as well as secondary alteration (Hunt, 1979; Tissot and Welte, 1984). Biodegradation commonly plays a key role in modifying oil properties among all secondary alteration processes (Connan, 1984; England, 1987; Volkman et al., 1984). Crude oils with different compositions have varying capacities for resisting biodegradation. For example, oils with light components, such as normal alkanes with low molecular weight, are preferentially degraded due to their relatively simple chemical structures (Connan, 1984; Larter et al., 2012; Peters et al., 2005; Volkman et al., 1983; Wenger et al., 2002). Biodegradation will therefore increase the relative contents of heavy components such as NSO compounds in crude oils, increasing the density and viscosity of the oils (Dou et al., 2005; Watson et al., 2002). Several schemes regarding to biodegradation levels have been proposed on the basis of compositional changes in key compounds in crude oils (Larter et al., 2012; Peters et al., 2005; Volkman et al., 1983; Wenger et al., 2002). Due to the limited conditions in which microorganisms that decompose hydrocarbons can survive, biodegradation usually occurs in shallow reservoirs with comparatively low formation temperatures (e.g. Lafargue and Barker, 1988; Peters et al., 2005; Seifert and Moldowan, 1979).

Water washing refers to the process in which groundwater dissolves and transports compounds with relatively low molecular weight or higher water solubility (Palmer, 1993). This process leads to the selective loss of light hydrocarbons, which changes the chemical compositions of the remaining oils (Bailey et al., 1973; Hemptinne et al., 2001; Palmer, 1984). Water washing and biodegradation usually occur together, and are difficult to distinguish (Connan, 1984; Kuo, 1994).

The Bongor Basin in Chad is a typical lacustrine passive faulted basin that has experienced two phases of tectonic inversion and has a complex history of petroleum generation and accumulation (Dou et al., 2011; Genik, 1992, 1993). In recent years, several studies have revealed that the physical properties and compositions of crude oils in the basin are complex, and that there are significant differences between crude oils in different areas, or at different burial depths, within the same oil field (Dou et al., 2011; Shi et al., 2011; Wen et al., 2013). Crude oils from the basin all have a genetic affinity and belong to a single oil family. The oils are conventionally divided into two subgroups according to their degree of biodegradation: normal oil and biodegraded oil (Cheng et al., 2018; Dou et al., 2011; Pan et al., 2013; Shi et al., 2011; Wen et al., 2013).

A great deal of work has already been done on the Lower Cretaceous petroleum system in the study area, including documentation of reservoir occurrence and features (Dou et al., 2019; Genik, 1993; Yan et al., 2019; Yu et al., 2019), assessment of source rocks, analysis of the geochemical characteristics of oils (Cheng et al., 2018; Dou et al., 2011; Pan et al., 2013; Shi et al., 2011; Wen et al., 2013), and determination of petroleum migration and filling processes (Chen et al., 2018; Dou et al., 2019). However, comparatively little research has been carried out on the characteristics of biodegraded oils and the geological constraints controlling the occurrence and degrees of biodegradation in the basin. In this study, the geochemical compositions of 41 crude oil samples from the basin are analyzed, with the intention of exploring the principal geological factors that determine the areal and sectional distribution of biodegraded oils in the basin. It is hoped that this will provide reference value for further oil exploration in the Bongor Basin.

Geological settings

The Bongor Basin is a Meso-Cenozoic passive rift lacustrine basin, situated at the intersection of the Central African Rift System and the West African Rift System, in southwestern Chad (Figure 1) (Genik, 1992, 1993). The basin extends in a NW-SE direction, with a spindle-shape, and covers an area of approximately 1.8 × 10⁴ km² (Dou et al., 2011). It can be divided into four secondary tectonic units: the Northern Slope, the Central Depression, the Southern Uplift, and the Southern Depression. The Northern Slope is considered to be the most favorable oil and gas exploration zone. The basin has a pre-Cambrian metamorphic rock basement overlain by tens of kilometers of Mesozoic-Cenozoic terrigenous clastic deposits (Chen et al., 2006a; Dou et al., 2011; Genik, 1993; Liu et al., 2012). Tectonic inversion in the Late Cretaceous strongly uplifted the entire basin, resulting in extreme erosion of the Upper Cretaceous strata. The strata deposited in this phase have been almost completely removed, with the erosion being more extensive in the northwest than in the southeast (Dou et al., 2011; Genik, 1992; Xiao et al., 2014). The Lower Cretaceous successions are subdivided into (from oldest to youngest) the Prosopis (P), Mimosa (M), Kubla (K), Ronier (R), and Baobab (B) formations (Dou et al., 2021). These represent the principal target intervals for oil and gas exploration in the basin. The Bongor Basin has a favorable combination of source-reservoir-cap rocks (Cai et al., 2010; Chen et al., 2006b; Dou et al., 2011; Liu et al., 2012; Song et al., 2009). The dark mudstones of the P and M formations are the primary source rocks for currently known petroleum accumulations. Reservoirs occur in various strata, mainly sandstones in the K formation and the lower part of the R formation. There are also three sets of regional caprocks, which are located at the tops of the P, K, and R formations.

Figure 1.

Schematic geological map of the Bongor Basin showing the well location of oils sampled in this study (modified after Dou et al., 2011; Genik, 1992).

Samples and experiments

Forty-one crude oil samples from the Lower Cretaceous P, M, K, and R formations in seven major oilfields located in the Northern Slope were analyzed in this study. The reservoir burial depths and the bulk properties of the oil samples are listed in Table 1.

Table 1.

The bulk geochemical compositions and selected geochemical parameters for oils from the Bongor Basin.

Well	Depth(m)	SAT%	ARO%	NSO%	ASP%	SAT/ARO	Wax%	BD*
Daniela 1-17	1363.9–1380.0	52.28	13.37	7.29	7.90	3.91	16.62	N
Laniea 2-3	922.5–1002.1	40.80	12.16	6.48	3.86	3.36	18.29	L
Mimosa N-1	866.0–873.0	49.19	20.29	10.88	7.31	2.42	4.51	L
Mimosa-9	1600.0–1660.0	57.28	12.97	7.91	6.33	4.41	18.45	N
Raphia S-1	811.7–826.6	57.76	11.78	7.76	2.16	4.90	17.65	N
Raphia S-11	1412.0–1474.9	56.56	12.34	5.47	1.72	4.58	17.07	N
Raphia-1	526.0–532.0	37.74	20.70	17.36	10.35	1.82	7.79	L
Ronier CN-1	1014.4–1024.0	32.14	15.29	10.28	5.39	2.10	1.20	S
Ronier D-1	2183.0–2188.8	65.77	6.68	1.50	0.90	9.84	22.49	N
Ronier 4-19	1538.7–1572.1	33.65	7.27	3.34	4.07	4.63	17.67	N
Prosopis 1-1	1565.9–1647.2	34.02	9.17	6.21	3.40	3.71	18.82	N
Baobab 1-3	1182.5–1253.1	44.89	19.67	17.12	5.56	2.28	21.10	N
Baobab N 1-21	1162.1–1247.8	49.37	16.93	11.29	4.75	2.92	23.07	L
BNE-18	1742.0–1856.1	50.48	16.98	10.16	2.22	2.97	18.30	N
BS 1-8	1533.5–1685.6	55.69	15.56	9.31	4.17	3.58	22.16	N
Baobab C-2	650.0	38.89	24.85	17.44	4.32	1.57	0.82	S
Baobab C-2	1106.0	37.18	23.40	19.39	8.17	1.59	0.45	S
Baobab C 1-15	Basement	46.78	15.59	12.54	7.45	3.00	14.66	S
Baobab N-8	1678.3–1692.8	35.30	10.30	7.06	26.39	3.43	10.45	N
Baobab N-8	1751.8–1765.0	44.32	8.73	9.28	15.37	5.08	7.79	N
Baobab S-6	2216.1–2219.1	43.94	12.58	7.14	5.90	3.49	18.99	L
Baobab-1	542.0–554.0	36.57	18.28	14.55	12.69	2.00	1.57	S
Mimson N-2	896.7–976.2	14.47	46.20	17.46	4.21	0.36	/	L
Raphia SW-2	969.0–1038.8	54.57	14.45	10.06	8.59	3.78	/	N
Raphia SW-2	969.0–1038.8(dehydration)	54.5	14.71	9.9	7.1	3.70	/	N
Raphia S-1	980.9–990.5	50.46	12.29	11.69	7.66	4.11	/	L
Raphia-1	1051.0–1053.0	61.24	12.57	13.11	3.87	4.87	/	L
Ronier-1	1012.0–1070.8	49.74	16.76	15.62	5.08	2.97	/	L
Baobab N 1-5	1089.5–1145.5	55.20	17.53	13.48	4.28	3.15	/	L
Baobab N 1-24	1431.1–1485.8	54.13	16.97	14.13	2.64	3.19	/	L
Baobab N-14	1267.0–1303.7	52.77	23.05	13.96	3.69	2.29	/	L
BNE-11	1362.0–1534.4	52.7	21.15	14.66	3.91	2.49	/	L
Baobab S-1	1385.6–1530.6	54.61	16.06	10.80	3.23	3.40	/	L
Baobab C-2	532.0–810.0	42.76	23.18	16.12	4.26	1.84	/	S
Baobab C-2	550.0	40.75	21.25	19.45	5.29	1.92	/	S
Baobab C-2	1002.0	42.85	23.09	19.37	2.85	1.86	/	S
Baobab C-2	1267.0	42.11	22.54	19.34	3.61	1.87	/	S
Baobab C-5	1306.9–2100.0	52.25	13.96	16.6	2.24	3.74	/	S
Baobab N-8	1388.0–1407.7	52.08	14.02	17.94	3.68	3.71	/	N
Baobab S-6	2276.6–2278.7	52.49	15.47	12.37	11.89	3.39	/	N
Baobab-1	1096.0–1107.0	51.77	25.32	17.1	3.11	2.04	/	L

Note: BD*= Biodegradation Degree; N=Normal oil; L=Slightly biodegraded oil; S=Severely biodegraded oil; SAT: Saturated fraction (wt%); ARO: Aromatic fraction (wt%); NSO: N-S-O compounds in crude oil (wt%); ASP: Asphaltenes (wt%); SAT/ARO: Ratio of Saturated/Aromatics

The oils were diasphaltened using petroleum ether and then fractionated using column chromatography on silica gel/neutral alumina (3:2, w/w) columns. Three fraction groups—saturated hydrocarbons, aromatic hydrocarbons, and NSO compounds—were sequentially separated using petroleum ether, dichloromethane/petroleum ether (2:1, v/v), and dichloromethane/methanol (93:7, v/v), respectively, as eluting solutions.

Saturated fractions was performed by gas chromatography (GC) analysis using a Shimadzu GC–2010 apparatus combined with an HP–5MS GC capillary column (30 m × 0.25 mm, 0.25 μm film thickness). The Flame Ionization Detector (FID) was used as the detector, with Helium as the carrier gas. The incipient oven temperature was set at 100°C, held for 1minute, and then increased to 300°C at a rate of 4°C/min. Finally, the temperature was held at 300°C for 25 min.

Saturated and aromatic fractions were analyzed by gas chromatography–mass spectrometry (GC–MS) equipped to an Agilent 5975i mass spectrometer with an Agilent 6890 gas chromatograph. A 60 m HP–5MS fused silica capillary column (0.25 mm i.d., 0.25 μm film thickness) was used. The temperature was held at 50°C for 1minute, then increased to 120°C at 20°C/min, and finally ramped up at 3°C/min to 310°C, where it was held for 25 min. Helium was again used as the carrier gas.

Results and discussion

The physical properties and bulk compositions of oils

The physical properties and bulk compositions of selected oil samples are shown in Table 1. There are obvious differences in physical characteristics among the oils. Generally speaking, increase in the NSO compound and asphaltene contents of crude oils increases their density and viscosity (Peters et al., 2005). For the oil samples in this study, the NSO and asphaltenes contents range from 2.40% to 33.45% (Table 1). Biodegradation may have reduced the contents of saturated hydrocarbons, and correspondingly increased the relative contents of asphaltenes (Dou et al., 2005; Duan and Chen 2007; Wang et al., 2011; Watson et al., 2002).

The relative contents of saturate hydrocarbons, aromatics, NSO compounds and asphaltenes are strongly influenced by thermal maturation levels and secondary alteration processes during the migration and accumulation of petroleum (Connan, 1984; Tissot and Welte, 1984; Xiao et al., 2019c). Generally, the relative NSO compounds and asphaltenes increase with the increasing of biodegradation (Peters et al., 2005). While the increase of maturation levels may lead to the increasing of relative contents of saturate hydrocarbons and aromatics. The low molecular weight hydrocarbons may relatively concentrate with the increasing of migration distance. The contents of saturated hydrocarbons and aromatics in the oils analyzed in this study were between 42.18%–87.86% and 8.93%–29.06%, respectively. The ratios of saturates to aromatics range from 1.57 to 9.84. Previous studies show indicate that all oils in the study area belong on single oil family within a narrow range of maturation variations. They were derived from the same oil source kitchen with a relatively short migration distance. Therefore, it is the varying extent of biodegradation rather than the maturity and migration distance exerts a significant impact on the bulk composition of crude oils.

The distribution of normal alkanes and acyclic isoprenoids

The initial stages of the biodegradation process are characterized by the removal of normal alkanes, due to their simple chemical structures, followed by the loss of acyclic isoprenoids and naphthenic hydrocarbons. Aromatic hydrocarbons are relatively resistant to biodegradation and constitute the stable fractions of oils with slight and moderate biodegradation levels (Peters et al., 2005). The abundance and distribution of normal alkanes and acyclic isoprenoids are normally used to evaluate the level of biodegradation.

Figure 2 shows the distribution patterns of normal alkanes and acyclic isoprenoids in oils with different burial depths. On the basis of gas chromatograms of saturated fractions, the samples can be divided into three subgroups: normal oils, slightly biodegraded oils, and severely biodegraded oils. Normal oils from the wells Raphia SW-2 and Mimosa-9 are characterized by intact n-alkanes and show straight baselines on gas chromatograms. By contrast, the oils from the wells Baobab S-6 and Mimosa N-2 show significant loss of n-alkanes and a slight ‘hump’ of the baseline on gas chromatograms, indicating that these oils have suffered slight biodegradation. The gas chromatograms of oils from the wells Ronier CN-1 and Baobab-1, show that n-alkanes and acyclic isoprenoids have been completely removed, and there is a marked baseline with an marked baseline ‘hump’, indicating that these oils have experienced severe biodegradation (Peters and Moldowan, 1991).

Figure 2.

Total ion currents (TIC) diagrams showing the distribution of normal alkanes and acyclic isoprenoids in the oils from the Bongor Basin.

Since acyclic isoprenoids are more resistant to biodegradation than their normal alkane counterparts, the relative abundance of acyclic isoprenoids, such as pristane and phytane to n-C₁₇ and n-C₁₈, respectively, can be used to evaluate degrees of biodegradation. The ratios Pr/nC₁₇ and Ph/nC₁₈ are generally lower for normal or slightly biodegraded oils, and gradually increase with increasing degree of biodegradation.

Figure 3 shows the relationships between the ratios Pr/nC₁₇ and Ph/nC₁₈ of the oils in the study area. The ratios Pr/nC₁₇ and Ph/nC₁₈ in the ranges 0.36 to 2.75, and 0.21 to 1.24, respectively. The cross-plot shows that these oils may have genetic affinity and derive from source rocks with mixed organic matter input and an oxidizing depositional environment. The differences in the Pr/nC₁₇ and Ph/nC₁₈ ratios may be mainly due to variations in the degrees of biodegradation of the oils.

Figure 3.

Cross-plot of Pr/nC₁₇ (the ratio of pristane to nC₁₇ alkane) vs. Ph/nC₁₈ (the ratio of phytane to nC₁₈ alkane) for oil samples from the Bongor Basin (after Shanmugam, 1985).

Previous studies have suggested that microbial demethylation of hopanes in severely biodegraded crude oil is one of the most important factors in the formation of the 25-norhopane series (Bennett et al., 2006; Moldowan and Mccaffrey, 1995; Peters et al., 2005; Volkman et al., 1983). The occurrence of 25-norhopanes in crude oils usually indicates severe biodegradation (PM > 6) (Bennett et al., 2006; Moldowan and Mccaffrey, 1995; Volkman et al., 1983). The complete 25-norhopane series, including C₂₉ 25-nor-17α(H)hopane, C₃₀–C₃₄ 25-nor-17α(H) hopanes (22S and 22R epimers), with the co-occurrence of their corresponding hopane series, are present in some oils. The distributions of hopanes and 25-norhopane series in representative oils are shown in Figure 4. For some severely biodegraded oils, such as the oils from the Well Ronier CN-1, the hopanes have been almost completely degraded and 25-norhopane series compounds have become the dominant components. By contrast, in oils from the Well Raphia-1, which have similar burial depths to those from the Well Ronier CN-1, no norhopane series compounds were detected.

Figure 4.

The m/z 177 and 191 mass chromatograms showing the distribution of hopane series and the 25-norhopanes in oil samples from the Bongor Basin.

Classification of oil family

The relative contents of C₂₇-C₂₈-C₂₉ regular steranes are commonly used as geochemical indicators for oil-to-oil and oil-to-source correlation (Moldowan et al., 1985). Figure 5 shows that the C₂₇–C₂₉ regular steranes in Bongor oils present an inverted “L”-shaped distribution pattern with a predominance of C₂₇ steranes. This indicates a predominance of lower aquatic organisms input in the source rocks. A ternary diagram of C₂₇-C₂₈-C₂₉ regular steranes (Figure 6(b)) shows that the oils belong to the same oil family and are derived from source rocks with a mixed input of planktonic and terrestrial plant organisms.

Figure 5.

The distribution of sterane series (m/z 217 mass chromatograms) in representative oils from the Bongor Basin.

Figure 6.

The ternary diagrams showing that all study oils belong to one oil family (a: after Xiao et al., 2019a; b: modified after Huang and Meinschein, 1979).

The relative abundances of C₁₉–C₂₃ tricyclic terpanes (TT) in petroleum and sedimentary organic matter are effective geochemical parameters for determining the lithology and depositional environment of organic matter (Moldowan et al., 1983; Peters et al., 2005; Xiao et al., 2019a). A ternary diagram showing the relative proportions of C₁₉₊₂₀ TT, C₂₁TT and C₂₃TT in the study samples indicates that these oils are likely to be derived from source rocks deposited in a lacustrine environment with brackish water bodies (Figures 6(a) and 7). The relative abundance of 22S to 22R epimers of C₃₁–C₃₅ homohopanes and 18α(H)-30-norneohopane (C₂₉Ts) to C₂₉ hopane are effective indicators for assessing the maturity of oils and source rocks. A cross-plot of C₃₂H 22S/(22S + 22R) to C₂₉Ts/(C₂₉Ts + C₂₉H) (Figure 8) shows that all the oils are at the mature stage and that there are no significant variations in maturity between the samples.

Figure 7.

The distribution patterns of tricyclic (TT) and tetracyclic (TeT) terpanes in selected oils from the Bongor Basin. Note: The number on the compound peak is carbon number of tricyclic and tetracyclic terpanes.

Figure 8.

Relationship between C₃₂H 22S/(22S + 22R) and C₂₉Ts/(C₂₉Ts + C₂₉H) of oil samples in the Bongor Basin.

Triaromatic steroids (TAS) are the most degradation-resistant aromatic components and are only removed to any significant extent in extremely biodegraded oils (PM 10). They are formed by the aromatization of their corresponding regular steranes (Peters et al., 2005; Yang et al., 2015; Zhang et al., 2016). TAS are believed to be effective molecular markers for oil-to-oil correlation of heavily to severely biodegraded petroleum (Li et al., 2012; Lin et al., 1989; Peters et al., 2005). A triangular diagram of C₂₆-C₂₇-C₂₈ triaromatic steroids (Figure 6(c)) reveals that all of the oils in this study are closely plotted in one group, indicating a high degree of similarity in the diagnostic molecular markers present in the samples and suggesting source affinity. Secondary alteration is therefore considered to be the main factor causing the variations in chemical and physical properties between the oils.

Geological conditions controlling oil biodegradation

Biodegradation is a common secondary alteration process that modifies the physical and chemical properties of oils at a rate far in excess of conventional geological processes (Connan, 1984; Huang, 2004; Palmer, 1993; Peters et al., 2005). Biodegradation usually occurs when the geological environment is favorable for the growth of microbial communities (Blanc and Connan, 1994; Connan, 1984; Palmer, 1993). Previous studies have revealed that contact with meteoric water and oil reservoir temperature are two of the main factors controlling the extent of oil biodegradation (Blanc and Connan, 1994; Wang et al., 2021). The burial depths of oil reservoirs and the connectivity between meteoric water and oils in the reservoirs are therefore key geological conditions for the occurrence of oil biodegradation.

Burial depths of reservoirs and the location of fault systems

The Bongor Basin, as part of the West and Central African Rift System, is a typical passive rift basin, which has undergone multiple stages of intense tectonic activity and has developed correspondingly complex fault systems (Dou et al., 2011; Genik, 1993). As shown in Figure 9(a), the framework of the structures in the Bongor Basin is principally controlled by the main fault systems along a NW-SE direction. Generally, frequent fault activity provides favorable opportunities for exchanges of meteoric fluids in oil reservoirs and the introduction of nutrient supplies for microorganisms, which promote microbial modification processes in the reservoirs (Guo et al., 2010; Wenger et al., 2002).

Figure 9.

Part of the locations of sampled wells and the occurrence of faults in the Bongor Basin.

In this study, it is found that all oils from reservoirs with a burial depth of less than 800 m have suffered moderate to heavy biodegradation. For example, oils in the reservoirs in wells BC-2 (650 m) and B1 (542–554 m) are typical biodegraded oils, in which normal alkanes and even acyclic isoprenoids have completely disappeared (Figure 2(f)). However, none of the oils from reservoirs with burial depths of greater than 1300 m present biodegradation characteristics (Figure 10). Oils with burial depths approximately within the range 800–1300 m, however, display varying degree of biodegradation even at similar depths (Figure 10), which suggests that other geological factors have impacted on the biodegradation process in these oils.

Figure 10.

Variations of Pr/nC₁₇ and Ph/nC₁₈ ratios with the burial depth of crude oils from the bongor basin.

Figure 9 shows the occurrence of main fault systems in the Bongor Basin. It can be observed that the distance between oil reservoirs and the fault plane is also a factor in influencing the degrees of oil biodegradation in the Bongor Basin, particularly for oil reservoirs with burial depths approximately in the range 800–1300 m. For example, the burial depth of the crude oil sample from well Raphia S-1 is relatively shallow (811.7–826.6 m) but it appears to be a normal oil with no trace of biodegradation. This can be attributed to the considerable distance between the oil reservoir and the nearest unclosed faults (Figure 9(c)). By contrast, the shallow burial depths and proximity to major faults of the oil reservoirs in Wells Mimosa N-1 (MN-1) and Baobab C-2 (BC-2) are conducive to the survival of microorganisms and the biodegradation of crude oils (Figure 9(b)). Similarly, although the oil from well BC-2 has a relatively deep burial depth of 1267.0 m, it has also suffered severe biodegradation because the reservoir is close to another deep fault oriented in the NNW-SSE direction (Figure 9(b)). It can be readily inferred that the biodegradation degree of oils in reservoirs with burial depths in the range 800–1300 m in the Bongor Basin is primarily controlled by the relative proximity of fault systems.

This phenomenon shows that deep faults can connect reservoirs to shallow formation water or meteoric water, which can transport microorganisms and dissolved oxygen into the reservoirs, increasing the susceptibility of the crude oils to biodegradation. Therefore, oil reservoirs in the Bongor Basin with burial depths of 800–1300 m are readily subjected to biodegradation when they are close to unclosed faults.

The evolution of structures and preservation conditions

The structural inversion that occurred in the Late Cretaceous caused strong uplifting of the Cretaceous strata in the rift basins of WCARS (Dou et al., 2011, 2021; Genik, 1993; Lai et al., 2018, 2020; Xiao et al., 2019b, 2019d). As a result, the Upper Cretaceous successions were severely eroded. For example, more than 1000 m of the K and R formations in Well BC-2, which form the regional caprocks for the underlying reservoirs, have been completely removed away (Figure 11). Although the burial depth of the basement reservoir in Well BC-2 is 1267.0 m in Well BC-2, that of the reservoir in the early Oligocene is less than c.a 800 m (Figure 11). Previous studies have indicated that oil charging in the Great Baobab Oilfield occurred during the Campanian (Dou et al., 2020; Wen et al., 2018; Xiao et al., 2014), which means that the oil reservoir had already formed when uplift and erosion occurred. Strong fault activity in this region, and significant uplift and erosion of strata, caused heavy biodegradation of the oils in Well BC-2. Secondary oil reservoirs may also have formed in overlying, shallower strata (Dou et al., 2011).

Figure 11.

Stratigraphic depositional-burial histories of well Baobab C-2 and well Raphia S-1 in the Bongor Basin.

In contrast, although the burial depth of the reservoir in Well Raphia S-1 is 811.7–826.6 m (Figure 11(b)), which is about 400 m shallower than that of Well BC-2 (Figure 11(a)), the oil in Well Raphia S-1 is normal oil with no significant biodegradation. The stratigraphic-burial curve of Well Raphia S-1 shows that it has a similar burial and oil charging history to Well BC-2. The difference is that, in the area of Well Raphia S-1, only part of the R Formation was eroded and the entire K Formation remained. These two formations served as favorable sealing rocks for the oil reservoir in the Lower K Formation. Relatively weak fault activity and the favorable sealing rocks combined to provide good preservation conditions for the oil reservoirs in this block so the oil has not experienced significant biodegradation.

Implication for oil exploration

Due to relatively weak fault activity, the limited occurrence of major faults, and favorable preservation conditions, all of the oils from the Raphia Oilfield are normal oils and do not have the characteristic signatures of biodegradation (Figure 12). Oils from the Mimosa and Ronier oilfields are predominantly normal, except for some oils from wells adjacent to major faults. The oil reservoirs in the Great Baobab oil field are mainly buried-hill reservoirs and generally have good preservation conditions. The oils in the Baobab South and North blocks are therefore normal or only slightly biodegraded. However, the oils in Well BC-2 have been severely biodegraded because of the relatively shallow burial depth of the reservoir and its proximity to major faults.

Figure 12.

The areal distribution of oil reservoirs with various degree of biodegradation in the main oilfields of the Bongor Basin.

This study may have practical implications for the exploration and discovery of normal oils in the Bongor Basin and surrounding region. The preferred targets are traps with burial depth greater than 1300 m, or shallower accumulations that are not immediately adjacent to major faults.

Conclusion

A total of 41 oil samples from oilfields in the Bangor Basin (Chad) were geochemically analyzed to investigate their molecular geochemical characteristics. The indicators of molecular biomarkers related to the source origin show that these oils belong to the same oil family and are derived from the same source kitchen. Biodegradation is considered to be the controlling factor leading to the differences in physical properties and molecular geochemical features between these oils. The oils can be divided into three subgroups, normal oils, slightly biodegraded oils and heavily biodegraded oils on the basis of the distributions of normal alkanes, acyclic isoprenoids, and the occurrence of “hump” of UCM (unresolved complex mixture) in the base line of gas chromatograms.

Variations in the degrees of biodegradation of the crude oil samples in this study are principally controlled by the burial depths of the oil reservoirs and the distances between reservoirs and the neighboring major faults. Oil reservoirs with burial depths of less than 800 m are found to have experienced heavy biodegradation, while those with depths greater than 1300 m are all normal oils with no significant degradation. In reservoir with burial depths between 800 m and 1300 m, the degrees of biodegradation of the crude oils vary from normal to severely degraded oils. The degree of oil biodegradation in these reservoirs is controlled by the distance between the reservoirs and adjacent faults, the features of caprocks, and the intensity of fault activity. This study supports prediction of the areal distributions of normal and biodegraded oils, which may have considerable practical significance for future oil exploration in the Bongor Basin and the surrounding region.

Footnotes

Acknowledgements

This study was sponsored by National Key Project (2016ZX05029). The authors are grateful to Shengbao Shi and Lei Zhu in the China University of Petroleum (Beijing) for their assistance in the geochemical analyses.

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research,authorship,and/or publication of this article.

Funding

The author(s) received no financial support for the research,authorship and/or publication of this article.

ORCID iD

Lirong Dou

Supplemental material

Supplemental material for this article is available online.

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Geochemical characteristics and origins of biodegraded oils in the Bongor Basin (Chad) and their implications for petroleum exploration

Abstract

Keywords

Introduction

Geological settings

Samples and experiments

Results and discussion

The physical properties and bulk compositions of oils

The distribution of normal alkanes and acyclic isoprenoids

Classification of oil family

Geological conditions controlling oil biodegradation

Burial depths of reservoirs and the location of fault systems

The evolution of structures and preservation conditions

Implication for oil exploration

Conclusion

Footnotes

Acknowledgements

Declaration of conflicting interests

Funding

ORCID iD

Supplemental material

References