Introduction

The Tethyan region is considered a major petroleum province where paleogeography and tectonic evolution have controlled the sedimentation and the development of essential elements for Mesozoic petroleum systems. In fact, the spatial distribution of source and reservoir rocks and their vertical stacking through time, as well as the trapping, maturation, expulsion, migration, accumulation, and preservation processes are closely related to the geodynamic evolution of the area. This was favored by widespread organic-rich sediments commonly called black shales that were deposited in most ocean basins during the Mesozoic worldwide oceanic anoxic events (Schlanger and Jenkyns 1976; Jenkyns 1988; Wignall and Myers 1988; Arthur et al. 1990; Cecca et al. 1994; Wignall 1994; Kuhnt et al. 1997; Barrett 1998; Sageman et al. 1998; Kuypers et al. 2002; Leckie et al. 2002; Luning and Kolonic 2003; Luning et al. 2004; Soua 2014a, b; Soua and Chihi, 2014; Talbi et al. 2018; Masrouhi et al. 2019; Talbi et al. 2021; Ben Ammar et al. 2021).

The most prominent of these oceanic anoxic events (OAEs) occurred in the Cretaceous such as the OAE1a (Selli event) (Elkhazri et al. 2013; Godet et al. 2014; Soua 2016; Talbi et al. 2018, 2021), OAE1b (Paquier event) (Bréhéret 1985; Khalifa et al. 2018), and OAE1d (Breistroffer event) (Schlanger and Jenkyns 1976; Talbi 1991), respectively, during early and late Albian, and OAE2 (Bonarelli event) at the Cenomanian–Turonian boundary (e.g. Arthur et al. 1988; Soua et al. 2022). Smaller-scale events of probably regional extent were also identified in several basins such as the middle Albian OAE1c and Coniacian-Santonian OAE3 (Burnett 1996; Arenillas et al. 2000; Jenkyns 2010; Ben Fadhel et al. 2011; Talbi et al. 2021; Ben Ammar et al. 2021).

These Cretaceous oceanic anoxic events (OAEs) are at the origin of the development, especially, of the Albian and Cenomanian–Turonian (C/T) world-class source rocks recorded in the northern African domain (Fig. 1b and c) (Arthur et al. 1990; Luning and Kolonic 2003; Luning et al. 2004; Soua 2014a, b; Soua and Chihi, 2014; Soua 2015; Talbi et al. 2018). These C/T with the other mid-Cretaceous source rocks have sourced almost one-third of the world’s HC reserves (Klemme and Uimishek, 1991; Luning et al. 2004).

Fig. 1
figure 1

a Paleogeographic reconstruction map of the western Tethyan domain during the early Cretaceous and Cenomanian–Turonian transition. Reconstructions were made after Barrier and Vrielynck 2008 and Tribovillard et al. 2012b Albian and c late Cenomanian–early Turonian in North Africa. Data were compiled from Luning et al. 2004; Zghal and Arnaud-Vanneau 2005; Baudin 2005; Reichelt 2005; Bodin et al. 2006; Chihaoui 2008; Jenkyns 2010; Ben Fadhel et al. 2011; Tribovillard et al. 2012

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In the southern Tethyan margin, namely in Tunisia and Algeria, the deposition of Cretaceous organic-rich sediments is strongly controlled by the development of (1) half-graben systems that occurred during the opening of the central and southern Atlantic oceans and the counter-clockwise rotation of African plate (Dercourt 2005; Scotese 2007; Fig. 1a), and (2) Triassic diapiric extrusion movements related to the global paleogeographical evolution during the Cretaceous, which succeeded the break-up of the Pangea supercontinent (Ziegler 1988; Veevers et al. 1994; Veevers 2004; Withjack et al. 1998; Golonka and Ford 2000; Golonka et al. 2002; Soua 2014a).

In Tunisia, the main Cretaceous-OAEs are recorded within the Albian lower Fahdene and the late Cenomanian-early Turonian Bahloul Fms (e.g. Talbi 1991; Saidi 1993; Luning et al. 2004; Affouri et al. 2013; Layeb et al. 2013; Soua 2015; Talbi et al. 2018; Ben Ammar et al. 2021; Talbi et al. 2021). These source rocks are proven as the main sources of hydrocarbons for many petroleum discoveries such as the onshore and offshore fields in central Tunisian Altas as well as the foreland basins of the Pelagian domain (e.g. Yukler et al. 1994; Saidi et al. 1998; Bédir et al. 2001; El Euchi et al. 2004; Klett 2022). However, previous basin modeling and geochemical studies (El Euchi et al. 2004; Mejri et al. 2006; Bédir et al 2020) showed that the most prolific organic-rich series are essentially represented by the Cenomanian–Turonian time interval.

These mid-Cretaceous source rocks are associated with several carbonate reservoirs (the Aptian Serdj, the Turonian-Coniacian Bireno and Douleb Fms, and the Campanian–Maastrichtian Abiod Fm; Ben Chaabane et al. 2018; Bédir et al. 2020; Soltani et al. 2022) and argillaceous seals (the Albian Fahdene, the upper Turonian-Santonian Aleg, and the Paleocene El Haria Fms). The most favorable traps, as recognized in the Sahel and Pelagian block basins, are mainly constituted by anticline structures, horsts, apex of titled blocks and locally Triassic salt domes/diapirs (e.g. Rabhi and Ben Ayed 1990; Masrouhi et al. 2008; Khomsi et al. 2009).

Therefore, successive tectonic events and halokinetic movements are generally responsible for the presence of numerous hydrocarbon seepages in northern Tunisia, especially in the diapir province (Belayouni et al. 1992; Belhaj Mohamed et al. 2015; Hallek and Montacer 2021).

In this context, special attention was given to the seepages identified during the fieldwork. Additionally, the aforementioned source rocks, reservoirs, seals, and Triassic salt dome traps, qualify this area as an important potential petroleum location for oil exploration. However, despite the notable efforts deployed in the evaluation of the petroleum potential of the upper Albian and the Cenomanian–Turonian source rocks in different regions of northern and eastern Tunisia, only a little attention was focused on their role as essential elements of active petroleum systems around Triassic salt domes structures.

The present work presents the first detailed geochemical investigation carried out on potential Cretaceous (Albian and Cenomanian–Turonian) source rocks and oil seeps belonging to the Triassic domes zone of northern Tunisia. It aims to (1) evaluate the ability of these source rocks to generate hydrocarbons and their possible genetic relation with the collected oil seeps, and (2) better understand the functioning of the region’s petroleum systems with special attention to the interplay between source rocks, reservoirs, and tectonics as possible hydrocarbon migration pathways.

Regional geology

Tunisia is located in the northeast part of the Maghreb domain which exposes numerous parallel structural trends bordered by major tectonic boundaries (Fig. 2a) where each zone is characterized by a proper deformation style. Four structural zones have been recognized in Tunisia (Fig. 2b and c): (1) the thrust belt with allochthonous to para-autochthonous highly folded and faulted upper Cretaceous to Eocene and Oligo-Miocene thrust sheet sediments (Rouvier 1977; Khomsi et al. 2009; Riahi et al. 2021), (2) the Tellian Medjerda molassic basin with fore-deep flexural subsidence and thick post-Atlassic sedimentation (Melki et al. 2012; Bejaoui et al. 2017), (3) the salt diapirs zone with NE–SW trending structures defining the “saliferous province” (e.g. Talbot 2005; Hamdi Naser et al. 2009), and (4) the Atlas zone marked by NE-SW trending asymmetric faulted folds (Masrouhi et al. 2013; Amri et al. 2020).

Fig. 2
figure 2

a The studied area within its regional geodynamic Mediterranean context (redrawn after Durand-Delga 1980). b Detailed geologic maps compiled from 1/50,000 geological maps (Dali 1994; Mahjoub and Dali 1998) showing the location of the studied area; c NW–SE synthetic and interpretative cross-section in northern Tunisia from the Alpine domain crossing the Atlas domain to the eastern Atlas foreland. Cross-section modified from Khomsi et al. 2009 and Martinez and Truillet 1987. d Synthetic stratigraphic chart of northern Tunisia based on the Tunisian Stratigraphic Chart (Ben Chalbi 2014, ETAP 2010) showing the position of the studied oil seep samples

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The northern Tunisian basin, belonging to the Atlas zone, was segmented into NE–SW trending tilted blocks that controlled the organic-rich strata deposition (Melki et al. 2012). At least four major NE–SW master faults have controlled differential subsidence and sedimentation patterns since the early Cretaceous. These faults formed weak zones for salt movement and doming and have been reactivated later for several times until the late Eocene and during the Miocene Alpine and Atlassic phases causing more complex salt diapir structures (Perthuisot 1978; Zargouni 1978; Bouaziz et al. 2002; Masrouhi et al. 2008; Khomsi et al. 2009; Melki et al. 2012).

Local geology

Structural context

The studied area, located in the south of Teboursouk village (Fig. 2b), covers the central part of the saliferous province occupied by the three Triassic salt domes of Ech-Cheid (Fig. 2b; sectors 1 and 2), Fej Lahdoum, and Boukhil (Fig. 2b; sector 3). These salt domes pertain to the Atlas foreland which is an intensely fractured zone owing to the succession of many tectonic events (Rouvier 1977; Durand-Delga 1980; Ben Ayed 1993; Melki et al. 2011). This is affected by strike-slip and thrust faults trending E-W, N-S, and NE–SW (Ben Ayed 1994; Vila 1995; Masrouhi et al. 2013).

Some authors (Jauzein 1967; Perthuisot 1978) emphasize a NE–SW major alignment formed by regional faults organized in a relay (the major Teboursouk overthrust) (Perthuisot 1978; Zargouni 1978). Later, Adil (1993) stated that this fault trend is the tectonic heritage from the Tethys opening. The tectonic faults are reactivated in strike-slip with conjugated structures in push-up and pull-apart. This fault system has facilitated the uplift of the Triassic material and the establishment of the Triassic piercing into the Mesozoic and Cenozoic coverage. However, in some previous works, the halokinetic movement in the region has occurred in two major periods: first doming during the Aptian times (Perthuisot 1978) and a second during middle Eocene times which is the probable period of surface piercing (Perthuisot 1978). The last Atlassic compression sculpted the definitive and actual Triassic structures and diapirs.

The El Alia-Teboursouk NE-SW trending master fault, recognized in the studied domain, represents one of these previously cited master faults which have a significant impact on sedimentation expressed by normal faulting that continued during the Cretaceous-Miocene interval, creating paleohighs and subsiding blocks (Bouaziz et al. 2002, Khomsi et al. 2006, Masrouhi et al. 2008, Frizon de Lamotte and Mouchard 2009, Melki et al. 2010, Melki et al. 2011; Fig. 2). This architecture is strongly witnessed by the obvious thickness and facies variations.

Post-relaxation normal faulting was observed in salt-cored anticlines in the whole area and gives more complexity to structures. These structures constitute a weak zone that allowed an easy migration of oil to the surface along faults and fractures. The main pathways for oil migration are considered to be controlled by the regional tectonic movements along NW–SE, N-S, E-W, and NE-SW trending normal faults (present work).

Lithostratigraphy

The lithostratigraphic column of outcropping strata is composed of two main sedimentary series (Mejri et al. 2006; ETAP 2010; Ben Chalbi et al. 2014; Arfaoui et al. 2018; Fig. 2d).

  1. (1)

    The Mesozoic strata comprise the following lithostratigraphic units:

The Triassic series of Ech-Cheid, Fej Lahdoum, and Boukhil domes consist of thick clay, dolomite, and evaporites intercalated by thin clay beds. The Jurassic series are dominated by nodular and siliceous limestones and marls. The early Cretaceous shales, marls, and thin clastic turbidites strata of M’Cherga Fm are followed by the late Aptian–early Albian sediments constituted by black clayey marls, sands, and fossiliferous limestone alternations. The mid-upper Albian Fahdene Fm which is one of the main potential source rocks was firstly described in the type locality of Oued Bahloul located to the south of Kesra village in central Tunisia (Burollet 1956) and consists of cyclic thinly laminated limestones alternating with marls and shales (Burollet 1956; Talbi 1991; Saidi 1993; Soua 2015). This formation constitutes the lateral equivalent of the shallow- marine carbonate/evaporite succession of the Zebbag Fm, developed in central-southern Tunisia (Soltani et al. 2022). The late Cretaceous is dominated by pelagic carbonates and marls of Cenomanian upper Fahdene member. It is followed by the late Cenomanian-early Turonian black shales and laminated limestones. The organic-rich Cenomanian–Turonian deposits in north-western, North-central, and Eastern Tunisia are generally composed of about 30–40 m thick of well-bedded dark grey to black bituminous limestone, with common local intercalations of marls and argillaceous limestone, and specify the Bahloul Fm (Burollet 1956; Layeb 1990; Saidi 1993; Soua 2015; Bachari et al. 2019; Hadded et al. 2021). The mode of arrangement of these facies highlighted the presence of three lithological units (U1, U2, and U3) of a regional correlating value (Layeb and Belyouni, 1989; Layeb et al. 2013; Touati and Haji 2018). The lower unit (U1) is majorly formed by laminated limestone commonly called black shale alternating with one to three marl levels and one or two beds of radiolarian siliceous limestone. The middle unit (U2) is characterized by the presence of four marl beds alternating with laminated black shale. The upper unit (U3) is composed of mainly less laminated limestone alternating with well-laminated black shale levels. This latter is overlaid by Turonian limestone beds of the Bireno member. Coniacian-Santonian marls and limy beds overlie the previous sequence. The upper Campanian-lower Maastrichtian deposits are represented by the Abiod Fm with alternations of white chalky limestones and marls.

  1. (2)

    The Cenozoic interval is composed of Paleocene marls rich in pelagic micro-fauna corresponding to El Haria Fm, Eocene limestones rich in nummulites (El Garia Fm.), and their equivalent globigerina organic-rich limestones (Bou Dabbous Fm). These deposits are related to the partial emersion of Jebel Ech-Cheid at the end of the Cretaceous period and which continued until the end of Eocene (Perthuisot 1978). Oligocene deltaic deposits are formed of siliceous sandstones (sandstone nodules), unconformably overlain by Miocene marls and post-Atlassic orogeny Pliocene–Quaternary continental conglomeratic beds.

Regarding the structural styles and deformations, we notice the importance of salt anomalies forming initial doming with at least two angular unconformities. These unconformities fossilize the main folding related to events previously described above. In addition, younger sediments unconformably overlay salt at the core and look like perched synclines. Such features outline a clear continuous salt activity and extrusion from both sides allowing a kind of flexural synform as is the case of the Jebel Ech-Cheid anticline.

At more advanced deformation salt anomalies evolve into diapirs injected along reverse faulting and thrusting. In fact, structures become more complex with detachment Triassic levels, folding and verticalized to reversed dipping strata like in Fej Lahdoum and Boukhil.

Material and methods

Samples

A total of 131 source rock and 10 oil seep samples, collected from three different sectors (sectors 1, 2, and 3) and different stratigraphic levels around the Ech-Cheid salt dome, were analyzed using Rock–Eval pyrolysis (RE-6) and biomarkers (GC–MS).

Source rock samples were collected from the lower Fahdene (52 samples) and the Bahloul (79 samples) Fms of different outcrop sections (Fig. 3; Table 1) located in sectors 1 and 2, while hydrocarbon seepages corresponding to oil stains, seeps mixed with water, asphalts and bitumen in the fresh break were taken from fractures/faults within the three sectors (Table 2; Figs. 4 and 5).

Fig. 3
figure 3

a Detailed geologic map of sector 1 from geological 1/50,000 map of Teboursouk (Perthuisot 1974) and b Detailed geologic map of sector 2 from geological 1/50,000 map of Gaafour (Dali 1994; Mahjoub and Dali 1998) showing the location of source rock samples

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Table 1 Designation and geographic coordinates of the studied source rocks
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Table 2 Location, short names, and geographic coordinates of the studied oil seep samples
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Fig. 4
figure 4

Photos illustrating the selected oil seep samples from the study area, in sector 1: a oil seep hosted in the Triassic-Miocene contact mixed with water in Rous Souani; b sample from the Albian carbonate facies of Fahdene formation along the fault in Oued Siliana; c sample from the Albian carbonate facies along the fault in Jebel Rihane; and from sector 2: d sample from the Turonian carbonate facies in Lakhaouat mine; e sample from the Santonian carbonate facies along the fault in Oued Behima; f sample from the Coniacian carbonate facies along the fault in Sidi Bilel; from sector 3: g sample from the Albian carbonate facies in Fej Lahdoum; h sample from the Campanian carbonate facies in Boukhil mine (see arrows and references therein)

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Fig. 5
figure 5

a Detailed geologic map from geological 1/50000 map of Teboursouk (Perthuisot 1974) with (AA’) geological cross-section in North Ech-Cheid (Ben Slama 2011) showing the location of oil seep samples from sector 1. b Detailed geologic map from geological 1/50,000 map of Gaafour (Dali 1994; Mahjoub and Dali 1998) with (BB’) geological cross-section in North Ech-Cheid (Ben Slama 2011) showing the location of oil seep samples from sector 2. c Detailed geologic map compiled from geological 1/50,000 map of Teboursouk (Perthuisot 1974) and Gaafour (Dali 1994; Mahjoub and Dali 1998) with (CC’) geological cross-section of Fej Lahdoum and Boukhil outcrops showing the location of oil seep samples from sector 3

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The first sector (sector 1) represents the northeastern Ech-Cheid outcrops (Fig. 3a) with main lower Fahdene sections at Oued Siliana (OS-LF) and Jebel Rihane (JR-LF), and Bahloul sections from Oued Siliana (OS-BH) and Kenana (KN-BH) outcrops. Three oil seep samples located North-Est of Ech-Cheid were collected (Rous-Essouani: OS1, Oued Siliana: OS2, Jebel Rihane: OS3). They consist of black material mixed with water or sample and from fractures in fresh breakage (Table 2, Fig. 5a, section AA’ of Ben Slama 2011).

In sector 2, located in the South-West of Ech-Cheïd and Lakhaouat outcrops (Fig. 3b), samples were collected from the Lakhaouat section (LK-LF) for lower Fahdene Fm and from Lakhaouat West Flank (LKWF-BH), Lakhaouat mine (LKM-BH), and Oued Merir section (OMR-BH) for Bahloul Fm (Table 1). Five oil seeps were sampled here at the surface from Triassic evaporites (OS4) and Santonian (OS6), Coniacian (OS7), and Turonian (OS8) carbonates (Fig. 5b). Most prominently, bitumen is found filling fresh breakage or fractures. One sample is collected from the borehole mining core in Lakhaouat Mine (OS5) from Turonian carbonate facies (Table 2, Fig. 5b, section BB’ of Ben Slama 2011).

In sector 3, two samples were collected from Fej Lahdoum (OS9) and Boukhil (OS10) mines, respectively from the Albian to Cenomanian Fahdene borehole core carbonates and the Campanian to Maastrichtian Abiod Fm (Fig. 5c, Table 2).

TOC analysis and Rock–Eval pyrolysis

Total organic carbon (TOC) and Rock–Eval pyrolysis were performed on 70 mg of the crushed rock sample using a Rock–Eval 6 instrument equipped with a TOC module (IFP Rock–Eval methods). The samples were first heated from 300 to 650 ºC (at 25 °C/mn) in a nitrogen atmosphere in order to quantify the free hydrocarbons (S1: mg HC/g rock), the potential hydrocarbons (S2: mg HC/g rock), carbon dioxide expelled during pyrolysis of kerogen (S3: mg CO2/g rock), and the temperature of maximum yield of pyrolysis (Tmax °C). The residual carbon is obtained during the oxidation cycle of the already pyrolyzed sample (heated from 300 to 800 °C) by summing the organic carbon oxidized into CO (S4 CO peak) and CO2 (S4 CO2 peak). The total organic carbon (TOC) is then determined by the summation of pyrolyzed carbon (PC: 0.083 (S1 + S2)) and residual carbon (RC: S4/10). Several additional parameters including HI (hydrogen index: S2 × 100/TOC), OI (oxygen index: S3 × 100/TOC), and PI (production index: S1/(S1 + S2)) (Behar et al. 2001) were calculated.

Bitumen extraction

Source rock extracts were obtained from six selected samples: three samples from the lower Fahdene source rock (JR-LF-9 and OS-LF-4 from sector 1, and LK-LF-5 from sector 2) and three others from the Bahloul source rock (OS-BH-33 from sector 1 and LK-BH-2, and OMR-BH-3 from sector 2).

The C15 + soluble organic matter (SOM) or source rock extract (EOM) was solvent-extracted with dichloromethane (CH2Cl2) in a Soxhlet apparatus using cellulose thimbles (12 h). Rapid extraction was performed for the oil seep to separate the organic fraction from the rest of the rock with a mixture of dichloromethane and methanol (90: 10 vol %) for 72 h using a Soxhlet extraction apparatus. The solution containing the EOM was rotary evaporated to a smaller volume and preserved in a 4 ml vial for asphaltene precipitation and fractionation into aliphatic and aromatic hydrocarbons and polar compounds.

Total extracts were separated into saturate, aromatic, and NSO-compounds fractions by liquid chromatography using a mini-column (Pasteur Pipette) packed with activated silica gel. These were eluted using nC5/CH2Cl2 (65/65, V/V) and CH2Cl2/methanol (90/10, V/V), respectively.

Biomolecular GC–MS

GC–MS analyses were conducted on the saturated and aromatic fractions in the oil seeps and source rock extracts (Bitumen) using an Agilent 7683B quadrupole mass-spectrometer coupled to a 7890A gas chromatograph. The gas chromatograph was equipped with a DB-1MS fused silica capillary column of 60 m in length, 0.25 mm i.d., and 0.25 μm film thickness. Helium was used as the carrier gas with a flow rate of 1 ml/mn. The oven temperature was programmed from 50 (hold time 10 mn) to 170 °C (hold time 15 mn) at 5 °C/min, to 300 °C (hold time 24 mn) at 1.5 °C/mn. The mass spectrometer was operated in EI mode at ionization energy of 70 eV and a source temperature of 300 °C. The biomarker contents were determined (Table 5) using single ion monitoring n-alkanes (m/z 85), terpanes (m/z 191) (Table 3), steranes (m/z 217), and triaromatic steroids (m/z 231).

Table 3 Peak assignment for Triterpanes (m/z 191), Steranes (m/z 217), and aromatic biomarkers (m/z 231) of oil seeps samples from GC–MS chromatograms based on Philip (1985) and Peters and Moldowan (1993)
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Hierarchical cluster analysis

Hierarchical cluster analysis (HCA) was performed in order to group the oil seep samples and oil with source rock s. The analysis was completed using autoscale preprocessing and Euclidean metric distance following the method of Ward (1963). The analysis included different selected biomarkers.

Results

Rock–Eval pyrolysis of potential source rocks

Lower Fahdene Fm

The geochemical log presented in Fig. 6 summarizes the total organic carbon (TOC) content and Rock–Eval parameters related to the lower Fahdene samples collected from sector 1. About 50% of the samples have TOC content higher than 1 wt.%. In Jebel Rihane (JR-LF), the TOC contents vary from 0.25 to 1.52 wt.%, 1.06 to 2.06 wt.%, and 0.70 to 2.52 wt.% in the basal, middle, and upper units, respectively.

Fig. 6
figure 6

Geochemical log of the lower Fahdene Formation outcropping at Jebel Rihane

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The lithological column exhibits variable petroleum potential (PP) values ranging from 0.11 to 2.40 mg HC/g rock, 1.96 to 3.36 mg HC/g rock, and 0.55 to 4.87 mg HC/g rock in the basal, middle, and upper units, respectively.

In Oued Siliana section (OS-LF), the TOC contents range from 0.13 to 1.14 wt.% with a mean of 0.49 wt.% (Table 4). The PP is also variable ranging between 0.09 and 5.29 mg HC/g rock, with an average value equal to 1.03 mg HC/g rock.

Table 4 Geochemical parameters recorded from Rock–Eval pyrolysis of the lower Fahdene and Bahloul source rocks
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Toward South-West (sector 2), samples from Lakhaouat locality (LK-LF), have TOC values ranging between 0.58 and 1.86 wt.% with a mean of 1.02 wt.% (Table 4). The PP values vary from 1.06 to 5.10 with a mean of 2.82 mg of HC/g TOC.

In the two investigated cross-sections of sector 1, the Fahdene OM shows HI, OI, and Tmax values ranging between 31 and 265 mg HC/g TOC, 6 and 220 mg CO2/g TOC, and 471 and 459 °C respectively.

In sector 2, the Lakhaouat locality shows HI values ranging from 154 to 386 mg HC/g TOC, with OI and Tmax values in the range of 38–106 mg CO2/g TOC and 429–439 °C, respectively (Table 4).

Bahloul Fm

The TOC contents and Rock–Eval pyrolysis results of the Bahloul samples are shown in Table 4 and Fig. 7. The stratigraphic distribution of the TOC contents throughout the Oued Siliana section (OS-BH) in sector 1 (Fig. 7) shows maximum values at the base of the lower unit (U1) up to 5.13 wt.% TOC. However, in the middle (U2) and the upper (U3) units, TOC values are in the range of 1.05 to 2.27 wt.% and 0.18 to 2.63 wt.%, respectively.

Fig. 7
figure 7

Geochemical log of the Bahloul Formation outcropping at Oued Siliana (Saidi 2003)

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The PP varies from 1.5 to 18.61 mg HC/g rock in unit1 (U1), 2.61 to 6.39 mg HC/g rock, and 0.45 to 9.12 mg HC/g rock in unit 2 (U2) and unit 3 (U3), respectively.

In Kenana section (KN-BH) of sector 1, the TOC values vary from 1.07 to 6.44 wt.% (Table 4). The PP ranges between 4.34 and 29.44 mg HC/g rock with a mean of 9.89 mg HC/g rock.

In sector 2, the samples collected from Oued Merir (OMR-BH), display variable TOC contents ranging between 1.1 and 8.61 wt. % with a mean of 4.92 wt.%. Their PP values range between 2.27 and 67.43 mg HC/g rock.

In Lakhaouat section and Lakhaouat mine, the TOC contents range from 2.58 to 6.01 wt.% and from 2.15 to 6.86 wt. %, respectively. The PP values vary between 20.73 and 43.51 mg HC/g rock in Lakhaouat section and from 8.56 to 34.48 mg HC/g rock in Lakhaouat mine.

In the two investigated cross-sections of sector 1, the OM preserved in the Bahloul Fm of Oued Siliana (OS-BH) and Kenana (KN-BH) is characterized by HI values in the range of 107–459 mg HC/g TOC with OI values between 7 and 91 mg CO2/g TOC, and average Tmax values of 438 °C in Kenana and 441 °C in Oued Siliana.

In sector 2, samples collected from Oued Merir (OMR-BH), Lakhaouat section (LKWF-BH), and Lakhaouat mine (LKM-BH), the HI, OI, and Tmax values are in the range of 203–775 mg HC/g TOC, 10–151 mg CO2/g TOC, and 419–438 °C, respectively (Table 4).

Molecular geochemistry

Source rock bitumen

Three extracted source rock samples from Fahdene Fm (two samples: JR-LF9 and OS-LF4 from sector 1 and one sample: LK-LF5 from sector 2), as well as three extracts from Bahloul Fm (OS-BH33 from sector 1 and LKM-BH2, and OMR-BH3 from sector 2), were analyzed (Fig. 8).

Fig. 8
figure 8

Mass chromatograms showing the distribution of aliphatic fraction (m/z 85), terpanes (m/z 191), steranes (m/z 217), and tri-aromatics (m/z 231) of the lower Fahdene and the Bahloul source rocks from sectors 1 and 2 (for key, see Table 3)

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In general, n-alkanes exhibit a unimodal distribution ranging from n-C11 to n-C35 with a dominance of short-chain compounds around n-C17 (Fig. 8). Pristane (Pr) and phytane (Ph) are present but less abundant than the adjacent n-C17 and n-C18 alkanes, resulting in low Pr/n-C17 and Ph/n-C18 ratios < 1 (Fig. 8; Table 5). Pr/Ph ratios range from 1.34 to 2.09 and from 0.46 to 0.95 for lower Fahdene and Bahloul samples, respectively (Fig. 8; Table 5). The degree of waxiness is between 0.28–0.82 and 0.20–0.36 in lower Fahdene and Bahloul source rock extracts, respectively (Table 5).

Table 5 Biomarkers parameters of oil seeps (OS1-10) and bitumen from source rock samples
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The analysis of terpanes biomarkers (m/z 191) shows that C19- to C25-tricyclic terpanes are present in samples from the two sectors (Fig. 8) but their abundance is generally low as indicated by the low C23tr/C30H ratios ranging from 0.05 to 0.37 in the Bahloul Fm and 0.13 in the lower Fahdene Fm (excepting JR-LF-9 sample in sector 1: 2.19). C23 is the most abundant tricyclic terpane and C19tr/C23tr ratios are generally lower than 1.0 (0.11–0.44 and 0.28–0.88 for the lower Fahdene and Bahloul extracts, respectively). The C22tr/C21tr and C26tr/C25tr tricyclic terpane ratios for the lower Fahdene samples are 0.17–0.24 and 1.16–2.58, respectively, while for the Bahloul Fm samples they range from 0.11 to 0.21 and 0.58 to 0.95, respectively.

Complete C27 to C35-17α(H), 21β(H)-hopane series were detected in all samples (Fig. 8). The regular 17α(H), 21β(H)-hopane (C30H) is the most abundant pentacyclic terpane in all the source rock extracts. C29-αβ/C30-αβ ratios vary, in general, from 0.38 to 0.68 in the lower Fahdene Fm and from 0.40 to 0.66 in the Bahloul Fm. The gammacerane (G) was detected in all samples in low to very low concentrations compared to C30-αβ hopanes (G/(G + C30H) ratio < 0.13). Extended hopanes or homohopanes are dominated by C31-homohopane (C31HH) and generally decrease toward the C35-homohopane (C35HH) (Fig. 8). The homohopane (C31HH-C35HH) distribution exhibits relatively low C35HH/C34HH values ranging between 0.56 and 0.78 in the lower Fahdene and between 0.77 and 0.97 in the Bahloul samples (Table 5).

The C27, C28, and C29 steranes have similar distributions (C29 > C27 > C28) in samples of the lower Fahdene and Bahloul Fms from different sections, except sample LKM-BH-2 in sector 2 which shows a slight predominance of C27 (37%) over the C29 (34%) and C28 (29%) homologous (Table 5). Relative abundances of C27, C28, and C29 regular steranes of the lower Fahdene Fm range between 33 and 37%, 22 and 29%, and 38 and 40% respectively, and those of the Bahloul bitumen range between 35 and 37%, 19 and 28%, and 34 and 44%, respectively (Table 5).

The diasteranes content of the lower Fahdene bitumen is fair to high (C27βα/C27αα range: 1.02–2.69), unlike that recorded in the Bahloul samples which are low to fair (0.20–0.70). C30-sterane was recorded in small quantities in analyzed source rock bitumen (Table 5). The distribution ranges of C29-steranes 20S/(20S + 20R) and αββ/(αββ + ααα) in the lower Fahdene extracts vary between 0.37–0.63 and 0.16–0.59, respectively, and 0.37–0.43 and 0.16–0.69 in the Bahloul extracts, respectively.

The analyzed biomarker maturity parameters show the high C2920S/(20S + 20R)(0.51–0.53) and ββ/(ββ + αα) (0.59–0.60) sterane ratios in the lower Fahdene samples of Oued Siliana (OS-LF4) and Jebel Rihane (JR-LF9), respectively, in sector 1 (Table 5). However, in sector 2 of Jebel Ech-Cheid, the lower Fahdene of Lakhaouat section (LK-LF5) exhibits low 20S/(20S + 20R) and ββ/(ββ + αα) C29 sterane ratios (0.31 and 0.37, respectively) (Table 5). Likewise, the Bahloul samples outcropping in the Oued Merir (OMR-BH3, sector 2) section exhibit the lower 20S/(20S + 20R) sterane (in the order of 0.42) and ββ/(ββ + αα) C29 sterane ratios (in the order of 0.16). Conversely, in sector 1, the Oued Siliana (OS-BH33) section exhibits the high 20S/(20S + 20R) sterane (in the order of 0.43) and ββ/(ββ + αα) C29 sterane (0.59) ratios.

The m/z 231 mass-chromatograms show the distribution of triaromatic steroids (TAS) in the lower Fahdene and Bahloul bitumen (Fig. 8) ranging between 0.06 and 0.83 in the lower Fahdene Fm and 0.08 to 0.15 in the Bahloul Fm (Table 5) (Peters et al. 2005).

In sector 1, samples of lower Fahdene and Bahloul Fms are characterized by high TAS values (0.80–0.83 and 0.14–0.15, respectively), while in sector 2 they are low (0.06 and 0.08, respectively).

The distributions of triaromatic steroids are characterized by a relatively high abundance of C2620R + C2720S, C2820S, and C2820R triaromatic steroids, while C2620S occurs as least (Fig. 8). Samples OS-LF-4 and JR-LF-9 in sector 1 reveal the predominance of C20 and C21 TAS peaks over higher homologous, while C26 20R + C27 20S are predominant in all samples except sample OS-BH-33 in sector 1 which C26 compounds occur in relatively low abundance (Fig. 8). Ratios of C26-/C28-TA (20S) and C20-TA/(C20 + C28R)-TA in the lower Fahdene and Bahloul samples are 0.50, 0.60, and 0.88 and 0.58, 0.69, and 0.33, respectively, in sector 1, while values decreased in sector 2 (in the order of 0.30–0.38 and 0.23, respectively) (Peters et al. 2005).

Oil seeps and bitumen impregnations

The mass chromatograms m/z 85 of OS1 and OS2 samples from sector 1 show a unimodal n-alkanes distribution ranging between n-C12 and n-C34 + and maximizing at n-C16 and n-C18 excepting the OS3 sample from sector 1 which shows a bimodal distribution of n-alkanes that maximizes at n-C25 (Fig. 9). The studied oil seep samples are characterized by relatively high abundance of n-C15 to n-C20 alkanes in the saturate fraction as indicated by the low degree of waxiness (0.53–0.77). However, the degree of waxiness in the OS3 sample is relatively high (2.42) (Table 5). The samples from sector 1 have no clear odd/oven carbon number predominance with CPI ranging from 1.04 to 1.18. The Pr/Ph ratio values are relatively fair (between 1.00 and 1.35) (Peters et al. 2005).

Fig. 9
figure 9

Mass chromatograms (m/z 85) of the aliphatic fractions showing the n-alkanes and acyclic isoprenoids distribution of the selected oil seep samples (for key, see Table 3)

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The OS4, OS5, OS6, and OS8 samples from sector 2 show a unimodal n-alkanes distribution ranging between n-C12 and n-C34 + with a maximum at n-C16 and n-C18 excepting OS7 from sector 2 which shows a bimodal distribution of n-alkanes maximizing at n-C25 (Fig. 9). The samples OS5, OS6, OS7, and OS8 are characterized by relatively high abundance of n-C15 to n-C20 alkanes and the low degree of waxiness (0.39–0.84) in the saturate fraction. The degree of waxiness in the OS4 sample is relatively high (1.99) (Table 5). The CPI of samples from sector 2 ranges from 0.99 to 1.12. The Pr/Ph ratio values are high (between 1.21 and 1.75) with the exception of OS4 and OS5 samples characterized by low values of Pr/Ph ratios in the order of 0.18 (< 1).

The OS9 and OS10 samples from sector 3 show a unimodal n-alkanes distribution ranging between n-C12 and n-C34 + and maximizing at n-C16 and n-C18 (Fig. 9) with the relatively high abundance of n-C15 to n-C20 alkanes and the low degree of waxiness (0.43–0.55) in the saturate fraction. The CPI and Pr/Ph ratio values range from 0.97 to 1.07 and between 0.56 and 0.59 (< 1), respectively.

The values of Pr/n-C17 and Ph/n-C18 ratios in sector 1 range between 0.56–1.01 and 0.45–1.01, respectively (Table 5), while ratio values range between 0.20–0.67 and 0.28–1.52 in sector 2 and between 0.49–0.72 and 0.51–0.52 in sector 3 (Table 5).

The analyzed oil seep samples from sector 1 (OS1, OS2, OS3) have a higher abundance of pentacyclic terpanes than tricyclic terpanes (Fig. 10), with ratios of tricyclic (tr) to pentacyclic terpanes (H) materialized by the dominant peak of tricyclic terpanes is C23tr, showing an ascending trend of C19tr < C20tr < C21tr < C23tr. The C19tr/C23tr, and C24Tet/C26tr ratios are low ranging from 0.16 to 0.27 and from 0.52 to 0.78, respectively, while the C26tr/C25tr ratios are relatively high in the range of 0.85–1.00.

Fig. 10
figure 10

Mass chromatograms showing the distribution of terpanes (m/z 191) of selected oil seep samples (for key, see Table 3)

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The conventional hopane with a carbon number of 30αβH (C30-17α, 21β hopane) is the dominant peak. There are few rearranged hopanes, only a small amount of C29Ts (C29-18α-neohopanes) and an extremely small amount of 30 Diah (C30-17α-diahopanes) that were detected. The gammacerane indice (GI) is low in the analyzed samples (GI = 0.04–0.07). The hopane distribution patterns are characterized by a regular stair-step progression of C31 to C35 homohopanes (C31HH-C35HH) with the predominance of 22S over 22R epimers. These samples display low to fair C35 HH/C34 HH (0.55–0.68) and small homohopane indices (C35HH/C31HH-C35HH), ranging between 0.05 and 0.08.

The analyzed samples from sector 2 (OS4, OS5, OS6, OS7, and OS8) have a higher abundance of pentacyclic terpanes than tricyclic terpanes (Fig. 10), with ratios of tricyclic (tr) to pentacyclic terpanes (H) materialized by low C23tr/C30H ratios ranging from 0.05 to 0.40. In almost the analyzed samples, the dominant peak of tricyclic terpanes is C23tr, showing an ascending trend of C19tr < C20tr < C21tr < C23tr. The C19tr/C23tr, and C24Tet/C26tr ratios are low, ranging from 0.15 to 0.22 and from 0.42 to 0.85, while the C26tr/C25tr ratios are relatively high in the range of 0.48–0.89 (Table 5).

The conventional hopane with a carbon number of 30αβH (C30-17α, 21β hopane) is the dominant peak in the analyzed samples. There are few rearranged hopanes, only a small amount of C29Ts (C29-18α-neohopanes) and an extremely small amount of 30 Diah (C30-17α-diahopanes) that were detected (Fig. 10). The content of gammacerane is low (GI = 0.05–0.10). The hopane distribution patterns are characterized by a regular stair-step progression of C31 to C35 homohopanes (C31HH-C35HH) with the predominance of 22S over 22R epimers. These samples display low to fair C35 HH/C34 HH (0.59–0.72) and small homohopane indices (C35HH/C31HH-C35HH), ranging between 0.06 and 0.07.

In sector 3, the analyzed samples (OS9, OS10) have a higher abundance of pentacyclic terpanes than tricyclic terpanes (Fig. 10), with ratios of tricyclic (tr) to pentacyclic terpanes (H) materialized by low C23tr/C30H ratios ranging from 0.11 to 0.66 (Table 5). In almost the analyzed samples, the dominant peak of tricyclic terpanes is C23tr, showing an ascending trend of C19tr < C20tr < C21tr < C23tr. The C19tr/C23tr, and C24Tet/C26tr ratios are low ranging from 0.10 to 0.17 and from 0.53 to 0.57. C26tr/C25tr ratios are relatively high in the range of 0.88–1.02 (Table 5).

The conventional hopane with a carbon number of 30αβH (C30-17α, 21β hopane) is the dominant peak in the analyzed oil seep samples. There are few rearranged hopanes, only a small amount of C29Ts (C29-18α-neohopanes) and an extremely small amount of 30 Diah (C30-17α-diahopanes) that were detected (Fig. 10). The content of gammacerane is low (GI = 0.02–0.13). The hopane distribution patterns of samples are characterized by a regular stair-step progression of C31 to C35 homohopanes (C31HH-C35HH) with the predominance of 22S over 22R epimers. These samples display low to fair C35 HH/C34 HH (0.68–1.00) and small homohopane indices (C35HH/C31HH-C35HH), ranging between 0.07 and 0.09.

In sector 1, the OS3 sample shows C29 regular steranes which are dominant over C27 and C28 steranes (C29ααR/C27ααR ratios in the order of 1.33). The rest of the oil seep samples (OS1 and OS2) have no C27 or C29 predominance (C29ααR/C27ααR: 0.96–1.03). The C27, C28, and C29 regular steranes contents are in the range of 34–43%, 24–31%, and 26–39%, respectively (Fig. 11; Table 5). The C27diasterane/C27 regular sterane (C27βα (R + S)/C27 αα (R + S)) ratios of the analyzed samples fluctuate between 0.58 and 1.39. Among these samples, OS1 displays the lowest C27βα (R + S)/C27 αα (R + S) value in the order of 0.58 indicating relatively low diasterane contents.

Fig. 11
figure 11

Mass chromatograms showing the distribution of steranes (m/z 217) of selected oil seep samples (for key, see Table 3)

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In sector 2, the relative abundance of regular steranes (C27, C28, and C29) differs greatly among oil seep samples. For OS4 and OS5 samples, there is no C27 or C29 predominance (C29ααR/C27ααR: 0.99–1.22).

For the OS6, OS7, and OS8 oil seep samples, the C29 regular steranes are dominant over C27 and C28 steranes (C29ααR/C27ααR ratios range from 1.10 to 1.86). The C27, C28, and C29 regular steranes contents are in the range of 29–35%, 26–34%, and 32–47%, respectively (Fig. 11; Table 5). In sector 3, for the OS9 sample, the C27 regular steranes predominate over C28 and C29 steranes (C29ααR/C27ααR = 0.88). The OS10 sample has no C27 or C29 predominance (C29ααR/C27ααR: 0.91). The C27, C28, and C29 regular steranes contents are in the range of 37–44%, 21–23%, and 36–40%, respectively (Fig. 11; Table 5).

The sterane distribution (m/z 217) indicates the lowest value of C27diasterane content, with high values of C29ααα20S/(20S + 20R) (0.36) and C29αββ/(αββ + ααα) (0.50) in OS1 sample (Table 5) while, OS2 and OS3 samples display the highest C27diasterane content and C29ααα20S/(20S + 20R) and C29αββ/(αββ + ααα) in the range of 0.52–0.57 and 0.49–0.54, respectively (Table 5).

The aromatic biomarkers (Table 5) show a low value of TAS (between 0.15 and 0.37) in OS1, OS2, and OS3 samples.

The C27diasterane/C27 regular sterane (C27βα (R + S)/C27 αα (R + S)) ratios of the OS4, OS5, OS6, OS7, and OS8 samples fluctuate between 0.17 and 1.80. The OS5 and OS7 samples display the lowest C27βα (R + S)/C27 αα (R + S) values ranging from 0.17 to 0.81 and indicating relatively low diasterane contents with C29 ααα20S/(20S + 20R) (0.46–0.69) and C29αββ/(αββ + ααα) (0.57–0.57), respectively (Table 5). However, OS4, OS6, and OS8 samples display the highest C27diasterane content, C29 ααα20S/(20S + 20R) in the order of 0.43–0.58, and C29αββ/(αββ + ααα) in the range of 0.46–0.53, respectively (Table 5). Additionally, the aromatic biomarkers (Table 5) show a low value of TAS (0.07) in the OS5 sample from the borehole mine in sector 2 whilst the TAS values of samples collected from the surface range between 0.16 and 0.32.

The OS9 sample displays the highest C27diasterane content with high C27βα (R + S)/C27 αα (R + S) value (in the order of 1.9), C29 ααα20S/(20S + 20R), and C29αββ/(αββ + ααα) ratios in the order of 0.42–0.46, respectively (Fig. 11; Table 5), while the OS10 one shows the lowest C27diasterane content with the lowest C27βα (R + S)/C27 αα (R + S) values (0.75) and C29 ααα20S/(20S + 20R), and C29αββ/(αββ + ααα) ratios (in the order of 0.41), respectively (Table 5).

The aromatic biomarkers (Table 5) for OS9 and OS10 samples of the borehole mine in sector 3 show TAS values varying between 0.01 and 0.03.

On the other hand, the oil-oil correlation using the C27βαS/C27ααS versus C29H/C30H (Fig. 14a) and C27βαS/C27ααS versus C24Tet/(C24Tet + C23) diagrams (Fig. 14b) shows the existence of three oil families marked by the difference of depositional environment and lithology.

Discussion

Richness, hydrocarbon generation potential, and typing of OM

In the studied sectors (1 and 2), the upper Albian lower Fahdene and the Cenomanian–Turonian Bahloul Fms are marked by moderate to good and moderate to excellent OM richness up to 4.78 wt.% and 8.10 wt.% TOC with a mean of 0.90 wt.% and 3.5 wt.% indicating fair to good and good to the excellent quality of the OM preserved in these Fms, respectively.

The TOC contents vary widely between samples and localities (Table 4): the highest TOC contents occurred in the middle and the upper parts of the Fahdene Fm, while the highest TOC contents characterize the lower (U1) and upper (U3) units of the Bahloul Fm.

The lateral variations suggest differences in palaeo-depositional settings between the localities, resulting in the decreasing TOC trend from NW to SE in sector 1 and the increasing TOC from NE to SW in sector 2 for the Fahdene Fm, while TOC variations show a slightly increasing from NE to SW in sector 1 and from South to North in sector 2 for the Bahloul Fm (Table 4).

According to the fact that TOC concentrations on the seafloor may record variations in surface bioproductivity and/or OM preservation during sedimentation and early diagenesis, the Fahdene and Bahloul Fms are considered to be deposited in a marine basin which was controlled by the interplay of subsidence and synsedimentary faults in tilted blocks associated with Triassic salt tectonics (Morgan et al. 1998; Grasso et al. 1999; Patriat et al. 2003; Soua et al. 2009; Hallek et al. 2019; Talbi et al. 2021; Ben Ammar et al. 2021). Thus, the highest average TOC contents in the studied sites (Table 4) coincide with subsiding zones (grabens and half-grabens) located around Triassic salt diapirs.

Additionally, in sector 1, the PP values registered in the Fahdene Fm of Jebel Rihane (JR-LF) are widely variable throughout the lithological column ranging from 0.11 to 2.40 mg HC/g rock, 1.96 to 3.36 mg HC/g rock, and 0.55 to 4.87 mg HC/g rock in the basal, middle, and upper units, respectively depending on their primary OM-richness and maturity level.

In the Oued Siliana section (OS-LF), located in the same sector 1, the PP ranges between 0.09 and 3.44 mg HC/g rock, with a mean of 1.03 mg HC/g rock indicating fair to good source rock, while in sector 2, the PP of the Fahdene Fm in Lakhaouat locality varies from 1.06 to 5.10 with a mean of 2.82 mg HC/g rock (Table 4). On the other hand, the S2 versus TOC plot (Fig. 12a) confirms that most samples display fair to good TOC contents and PP values indicating a fair to good source rock.

Fig. 12
figure 12

S2 vs. TOC (a), HI vs. Tmax (b) diagrams for the lower Fahdene Formation showing the richness and the maturity of organic matter. c S2 vs. TOC and d HI vs. Tmax diagrams for the Bahloul Formation showing the richness and the maturity of organic matter

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The PP values of the Bahloul Fm are also variable throughout the lithological column (Fig. 7). This can be clearly seen in the Oued Siliana section (OS-BH) in sector 1 where PP values range between 1.5 and 18.61 mg HC/g rock, 2.61 and 6.39 mg HC/g rock, and 0.45 and 9.12 mg HC/g rock in the lower (U1), middle (U2), and upper (U3) units, respectively, displaying a moderate to very good source rock.

In the Kenana section (KN-BH), the PP values range between 4.34 and 29.44 mg HC/g rock with a mean of 9.89 mg HC/g rock which indicates a good to very good source rock.

In sector 2, samples collected from Oued Merir (OMR-BH) show PP values ranging between 2.27 and 67.43 mg HC/g rock, while in the Lakhaouat section and Lakhaouat mine, they vary between 20.73 and 43.51 mg HC/g rock and 8.56 and 34.48 mg HC/g rock, respectively which is compatible with a good to the excellent source. The cross-plot S2 versus TOC (Fig. 12c) used for source quality and quantity assessments (Espitalie et al. 1985) shows fair to excellent TOC contents for the Bahloul Fm.

On the other hand, these mid-Cretaceous source rocks present variable HI and OI values (Table 4) depending on the quality and the preservation rate of OM. In this sense, the lower Fahdene Fm in the studied sections (sectors 1 and 2) shows relatively low HI (between 31 and 386, mean: 179 mg HC/g TOC) and low to high OI (6–220, mean: 64 mg CO2/g TOC) values typical of mixed marine and terrestrial type II-III kerogen and an advanced maturity level with local alteration of OM, respectively (Peters 1986; Peters and Cassa 1994) (Fig. 12b).

Moreover, the extracted samples of Fahdene Fm (JR-LF9 and OS-LF4 from sector 1 and LK-LF5 from sector 2) exhibit the high Pr/Ph, Pr/n-C17, and Ph/n-C18 ratios typical for a source rock with high contribution of terrestrial OM. Furthermore, the low GI and C35/C34-homohopanes ratios indicate a marine input of OM deposited under suboxic conditions with normal salinity water column (Peters and Moldowan 1993). The high abundance of C23tr, C22tr/C21tr, and C26tr/C25tr and the lowest to medium ratios of C29H/C30H and regular diasteranes over steranes (Table 5) are consistent with a marine argillaceous carbonate depositional environment (Waples and Machihara 1991).

For the Bahloul samples, HI values are fair to high (HI: 230–703, mean: 458 mg HC/g TOC) and OI are low (mean OI: 31 mg CO2/g TOC) which is compatible with a primarily marine type II OM (Fig. 12d).

Likewise, the extracted samples of Bahloul Fm (OS-BH33 from sector 1 and OMR-BH3 and LKM-BH2 from sector 2) show the low Pr/Ph, Pr/n-C17, and Ph/n-C18 ratios typical of source rock with high contribution of marine algal-OM. Additionally, the low GI and C35/C34-homohopanes ratios suggest a marine input of OM deposited under suboxic conditions with normal salinity water column (Peters and Moldowan 1993).

On the other hand, the high abundance of the C23tr and high C29H/C30H ratio with the low C22tr/C21tr and C26tr/C25tr, and the regular steranes over diasteranes (Table 5) are indicative of OM deposited in a carbonate-marl marine environment (Waples and Machihara 1991).

Thermal maturity of source rocks

The thermal maturity of OM in the analyzed rock samples is evaluated based on Tmax and production Index (PI) values (e.g. Tissot and Welte 1984; Waples 1985; Moldowan et al. 1986; Peters and Moldowan 1993) as well as on stereoisomerization ratios (Mackenzie et al. 1980; Peters et al. 2005).

The high Tmax (441–459 °C) and PI (0.1–0.3) values of the lower Fahdene Fm outcropping in sector 1 reflect the OM in Jebel Rihane and Oued Siliana sections are mature (Oil window). However, in sector 2, the Tmax values in the Lakhaouat section range between 428 and 439 °C with a mean of 432 °C and low PI (< 0.03) suggesting immature to marginally mature OM (Table 4; Fig. 12b).

The Bahloul source rock outcropping in sector 1 (Oued Siliana and Kenana localities) seems mature as indicated by the high Tmax (435–446 °C; Table 4) and PI values (0.03–0.23; Table 4) whereas, toward sector 2 (Oued Merir and Lakhaouat localities), the Bahloul Fm, characterized by low Tmax (< 435 °C) and PI (< 0.03) values, appears to be immature (Fig. 12d).

Regarding the biomarker maturity parameters, the high C2920S/(20S + 20R) sterane and ββ/(ββ + αα) sterane ratios with a relatively high TAS registered in the lower Fahdene samples of Oued Siliana (OS-LF4) and Jebel Rihane (JR-LF9) in sector 1 (Table 5) indicate a mature source rock. Toward sector 2, the lower Fahdene of Lakhaouat section (LK-LF5) exhibits low 20S/(20S + 20R) sterane and ββ/(ββ + αα) C29 sterane ratios with low TAS values, confirming the low maturity level of OM (Table 5). Likewise, the extracted sample of the Bahloul Fm (OS-BH33) of Oued Siliana locality located in sector 1 exhibits the high 20S/(20S + 20R) sterane, ββ/(ββ + αα) C29 sterane, and TAS values attesting to the high maturity level of OM. However, toward sector 2, the extracted sample in the Oued Merir section (OMR-BH3) exhibits lower ratios of 20S/(20S + 20R) and ββ/(ββ + αα) C29 sterane, and low TAS values indicating a low maturity level of OM.

In sum, the OM preserved in Fahdene and Bahloul Fms is mature (late oil window) in sector 1 and immature in sector 2. This may be explained by the basin architecture which seems to be marked by the presence of subsiding zones in sector 1 and up-lifted ones near Triassic paleohighs (i.e. Lakhaouat mine). Accordingly, a recent mineralogical investigation carried out by Jemmali et al. (2022) in the Lakhaouat Zn-Pb-(Ba-Sr) ore deposit, hosted mainly in the OM-rich Albian and Cenomanian–Turonian series, highlighted the presence of two types of fluid inclusions in calcite (Cal-2) corresponding to lower and higher maturities oils which were likely expelled at different stages of the Albian Fahdene and the Cenomanian–Turonian Bahloul source rocks.

Oil seeps and bitumen impregnations biomarkers signatures

Depositional environment

From n-alkanes and isoprenoids

In the three studied sectors, most oil seeps samples (OS1, 2, 4, 5, 6, 8, 9, and 10) show a unimodal n-alkanes distribution ranging between n-C12 and n-C34 + and maximizing at n-C16 to n-C18 with relatively high abundance of n-C15 to n-C20 alkanes (Fig. 9) and generally low degree of waxiness which indicate a marine origin of the primary OM (Moldowan et al. 1994), except the OS4 sample which is characterized by a high waxy compatible with a terrestrial OM contribution (Peters and Moldowan 1993; Moldowan et al. 1994).

Two samples only (OS3 from sector 1 and OS7 from sector 2) are characterized by a bimodal n-alkanes distribution that maximizes at n-C25 and n-C35, respectively (Fig. 9) with relatively high and low degrees of waxiness which suggest a high waxy nature with a contribution of terrestrial OM for OS3 sample and a marine source for the second (OS7 sample) (Peters and Moldowan 1993). Additionally, variations of Pr/n-C17 and Ph/n-C18 ratios between 0.20 and 1.01 and between 0.28 and 1.57, respectively (Table 5) indicate a primarily marine origin of OM with a significant algal contribution (Peters and Moldowan 1993). Furthermore, the cross-plot of these values on a diagram Pr/n-C17 vs. Ph/n-C18 (Fig. 13a) attests the studied oil seeps were generated from type II and type II-III OM sources.

Fig. 13
figure 13

a Cross-plot of Pr/n-C17 vs. Ph/n-C18 ratios of the studied oil seep samples (modified from Hunt 1995) showing the origin and the depositional environment of samples, b C27: C28: C29 regular steranes ternary diagram (modified after Huang and Meinschein 1979) showing the nature of the organic matter of the oil seep source rocks from Jebel Ech-Cheid and neighbouring structures. c Range of thermal maturity based on biomarker maturity ratios, i.e., C29S(S + R) steranes vs. C29ββ(αα + ββ) steranes showing the increasing thermal maturity of oil seep samples in the studied area

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On the other hand, all studied samples have no clear odd/oven carbon number predominance but with low (Pr/Ph < 1 for OS4, 5, 9, and 10) and relatively fair to moderate (1 < Pr/Ph < 1.75 for OS1, 2, 3, 6, 7, and 8) Pr/Ph values (Table 5) attesting to deposition and preservation of their source rocks under reducing (anoxic) and suboxic factors, respectively (Peters and Moldowan 1993; Moldowan et al. 1994; Peters et al. 2005). The anoxic depositional environments coincide with the southern flanks of Lakhaouat (OS4 and 5), Boukhil (OS9), and Fej Lahdoum (OS10) diapirs which are recognized as significant Zn-Pb sulfide ore deposits. These diapirs correspond to paleohighs occupied by Triassic salt domes with southern subsiding zones developed in local faulted blocks thus creating favorable environments for the accumulation and preservation of high quantities of OM.

From terpanes and hopanes (m/z 191)

The higher abundance of pentacyclic terpanes than tricyclic terpanes, the low C19tr/C23tr ratios, and concentrations of gammacerane of all studied samples (OS1, OS2, and OS3 from sector 1, OS4, OS5, OS6, OS7, and OS8 from sector 2, and OS9 and OS10 from sector 3) (Table 5) indicate a marine origin of their source rocks with a normal salinity water column. The low to fair C35HH/C34HH ratios and small homohopane indices (C35HH/C31HH-C35HH) suggest oxic to suboxic depositional conditions (Peters and Moldowan 1993) (Table 5).

Additionally, the relatively high C29 H/C30H and the medium to high C24Trt/C26Tr ratios of OS1 (from sector 1), OS5 and OS7 from sector 2, and OS 10 from sector 3) indicate that these oil seeps were sourced from marine marly carbonate source rocks. However, the low C29H/C30H and the low to medium C24Trt/C26tr ratios, registered in OS2 and OS3 from sector 1, OS4, OS6, and OS8 from sector 2, and OS9 from sector 3, suggest a marine argillaceous carbonate-rich source (Peters et al. 2005).

From diasteranes and steranes

In sector 1, the OS3 sample is characterized by C29 regular steranes which are dominant over C27 and C28 ones (C29ααR/C27ααR ratios in the order of 1.33), indicating a contribution of terrestrial OM in its source rock. The rest of the oil seep samples (OS1 and OS2) have no C27 or C29 predominance (C29ααR/C27ααR). The C27, C28, and C29 regular steranes contents are indicative of marine planktonic-bacterial OM as can be shown by the regular steranes distribution in the ternary diagram (Fig. 13b; Huang and Meinschein 1979). Among these samples, OS1 displays the lowest C27βα (R + S)/C27 αα (R + S) value (Table 5) and relatively low diasterane contents indicating a marl-carbonate lithology of its source rock. Conversely, the OS2 and OS3 samples show the highest C27βα(R + S)/C27αα (R + S) ratio values attesting to the argillaceous carbonate marine/lacustrine OM.

In sector 2, the OS4 and OS5 samples are marked by the absence of C27 or C29 predominance (C29ααR/C27ααR: 0.99–1.22) which indicates that these oil seeps were generated from a marine OM. For the OS6, OS7, and OS8 samples, the C29 regular steranes are dominant over C27 and C28 steranes (C29ααR/C27ααR ratios range from 1.10 to 1.86), while the OS4 and OS6 samples have a similar value of C27diasterane/C27 regular sterane than the OS2 and OS3 samples which is consistent with an argillaceous carbonate lithology of their source rocks. Unlike, the low values of C27βα (R + S)/C27 αα (R + S) in OS5 and OS7 samples have a similar marl-carbonate source rock lithology to the OS1 sample from sector 1 (Fig. 13b; Huang and Meinschein 1979).

In sector 3, for the OS9 sample, the predominance of C27 regular steranes and C29ααR/C27ααR, and the highest values of C27diasterane/C27 regular sterane (> 1) indicate an argillaceous marine source. However, the OS10 sample has no C27 or C29 predominance (C29ααR/C27ααR: 0.91), and the lowest ratios of C27diasterane/C27 regular sterane which is indicative of a marly-carbonate lithology of its source rock which contains a marine planktonic-bacterial OM supported also by the regular sterane distribution in the ternary diagram of Huang and Meinschein (1979) (Fig. 13b).

Oil maturity

In sector 1, the sterane distribution (m/z 217), characterized by the high C29ααα20S/(20S + 20R) and C29αββ/(αββ + ααα) values indicates that the three studied samples (OS1, OS2, and OS3) were generated from source rocks containing mature OM (Table 5; Fig. 13c). This is confirmed by the highest TAS values in aromatic biomarkers (Table 5).

In sector 2, the OS5 sample collected from the Lakhaouat mine displays relatively low C29 ααα20S/(20S + 20R) and C29αββ/(αββ + ααα), as well as low TAS aromatic values (Table 5) indicating an early mature stage of its source rock OM (Fig. 13c). Conversely, the OS4 (Lakhaouat mine) as well as OS6 and OS8 (SE of J. Ech-Cheid) samples, marked by the high C29ααα20S/(20S + 20R) and C29αββ/(αββ + ααα) and TAS values (Table 5), are generated from mature source rocks similar to those of sector 1 (Fig. 13c). Hence, we state, for a second time, the presence of low (OS5 sample) and high (OS4 sample) oil maturity stages in Lakhaouat mine, previously described by Jemmali et al. (2022) using a fluid inclusions investigation.

In sector 3, the OS9 sample (Fej Lahdoum mine) displays low C29ααα20S/(20S + 20R), C29αββ/(αββ + ααα), and TAS values (Table 5; Fig. 13c), attesting to early mature source rock, while the OS10 sample (Boukhil mine) exhibits the highest C29 ααα20S/(20S + 20R), C29αββ/(αββ + ααα), and TAS values suggesting that this sample was sourced from a mature source rock (Table 5; Fig. 13c).

Oil-oil and oil-source rock correlation

Previous studies (e.g. Gurgey 2003; Peters 2005) showed that the alkanes, terpanes, and steranes biomarkers may be used for correlation purposes (Table 5) since these compounds are resistant to different transformation phenomena. Four mature source rock samples have been selected according to their high values of Tmax, 20S/(20S + 20R) sterane, and ββ/(ββ + αα) C29 sterane ratios.

The hierarchical cluster analysis (HCA) (Peters and Fowler 2002) has been used to classify oils with different sources using the combination of different biomarker parameters (Fig. 14).

Fig. 14
figure 14

a Cross-plot of C27βαS/C27ββS Hopanes vs. C29/C30H Hopanes, b cross-plot of C27βαS/C27ββS Hopanes vs. C24Tetracyclic/C24Tetra + C23tricyclic Terpanes Hopanes illustrating the oil family of the studied samples, and the hierarchical cluster analysis (HCA) dendrogram (c) showing the oil seep/source rock family

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The obtained results show:

  • The OS5 and OS10 samples from sectors 2 and 3, respectively, belong to the family I.

These oils are characterized respectively by (1) low values of C27βα(R + S)/C27αα(R + S) and C19/C23 and moderate values of the gammacerane index, and (2) high values of Ts/Tm and C29ααα20S/(20S + 20R), which indicate that these oils are mature and appear to have been generated from a carbonate source rock deposited under anoxic conditions. Hence, they could be derived from the late Cenomanian-early Turonian Bahloul source rock;

  • The OS2 and OS3 samples from sector 1 and OS4, OS6, OS7, and OS8 samples from sector 2, and OS9 sample from sector 3 belong to the second family (Family II). These are characterized by (1) low values of C19/C23 (0.15–0.27) and gammacerane index (0.05–0.07), and (2) high ratio values of C27βα(R + S)/C27αα(R + S) (0.81–1.80), Ts/Tm (1.10–2.10), 20S/20S + 20R) (0.43–0.69), and C29 steranes ββ/(ββ + αα) (0.52–1.80). The aforementioned results, suggesting a mature source rock derived probably from a clayey predominantly facies deposited in a dysoxic environment, could be correlated with the lower Fahdene source rock;

  • The OS1 sample from sector 1 is classified in family III. It is characterized by the low gammacerane index, C19/C23, C27βα(R + S)/C27αα(R + S) values and the high Ts/Tm, 20S/20S + 20R), and C29 steranes ββ/(ββ + αα) values. This attests to that this oil is mature and probably sourced from both the lower Fahdene and Bahloul Fms and or other source rock which can be the mid-upper Barremian M’Cherga Fm recently recognized northward as a good potential source rock (Talbi et al. 2021; Ben Ammar et al. 2021). However, the comparison of biomarkers from an upper Barremian source rock sample of Jebel Bazina (Ben Ammar et al. 2021) with those from the Rous-Essouani oil seep sample (OS 1) showed the absence of significant correlation, which could indicate either an over-mature stage (Gas window) of the OM fossilized in the Barremian facies or different migration pathways of the generated hydrocarbons from those of the upper Albian and the Cenomanian–Turonian facies.

Petroleum system assessment

In the studied area, the integration of our results on thermal maturity with the published data clearly indicates that the degree of thermal maturity of lower Fahdene and Bahloul Fms is quite low (immature) towards the SW part of Ech-Cheid (Lakhaouat mine) as indicated by the relatively low Tmax values (in the range of 423 to 434 °C). Conversely, towards the northeast, the lower Fahdene (Upper Albian) and Bahloul (Cenomanian–Turonian) source rocks are mature to late mature as indicated by the relatively high Tmax values ranging between 440 and 446 °C (Chaari 2002; Affouri et al. 2013; Layeb et al. 2013; Ben Fadhel et al. 2014; Talbi et al. 2021; present work), and oil maturity biomarker signatures (high C29ααα20S/(20S + 20R), C29αββ/(αββ + ααα), and TAS values).

The increasing thermal maturity is attributed to the increased subsidence from the SW to the NE and the SE of the Ech-Cheid structure caused by regional tectonic movements along predominant NW–SE trending normal faults resulting from upper Cretaceous rifting. However, NE-SW inherited saliferous trends facilitated diapiric Atlassic structures. Minor N-S and E-W oriented faults are associated with the reactivation of deep faults inherited from Triassic-Jurassic Tethyan rifting. Such trends can be supported by oil seeps orientations along these directions (Chaari et al. 2003; Rddad et al 2019a, b). Hence, we consider that these directions may constitute the main pathways for oil migration from deeper to high domains. In fact, migration could occur along these faults and fractures in a convergent manner. For example, migration could be from NW to SE at the northern synform of the Ech-Cheid dome and from the SE to NW at the southern syncline, and the same for the other orientations. However, in the northern portion of sector 2, Cretaceous sediments, mainly of lower Fahdene and Bahloul Fms, were deposited near the paleohighs as a result of vertical movements of the Triassic salt dome in these locations since the lower Cretaceous (Layeb and Belayouni 1999; Jemmali et al. 2022). Hence, these potential source rocks were not buried enough to reach the maturity stage. The comparison of the geochemical results of the Cenomanian–Turonian and Albian facies according to a NE-SW transect extending from Oued Siliana shows that the thermal maturity decreases near the Triassic salt structure, whereas in the inter-diapiric zones, we notice an increase in the maturity level. In this context, as aforementioned above in the results section, the high maturity levels are registered in Jebel Rihane and Oued Siliana for the lower Fahdene Fm and in Oued Siliana, Kenana sites for the Bahloul Fm. These are considered to be the consequence of the interplay of subsidence and synsedimentary faults in tilted blocks associated with Triassic salt movements.

In summary, we state that the maturity level of mid-Cretaceous oil/gas source rocks is, here, mainly controlled by subsidence degrees in tilted blocks. For these reasons, Cretaceous sources could generate an amount/volume of HC that contributes to the charge of existent potential reservoir rocks around the area; this later could be middle-Turonian Bireno, Coniacian Douleb, the Campanian–Maastrichtian Abiod carbonate, and Oum Dhouil Miocene reservoirs. Cretaceous, Paleocene, and Miocene argillaceous Fms form the main seals for the above-described reservoirs. These results encourage exploration of (1) buried structures (anticlines, uplifted zones) surrounding the Ech-Cheid area on one hand and (2) buried salt anomalies analogous in the Sahel domain and north-western Tunisia, on the other hand.

Conclusion

The geochemical investigation carried out on the upper Albian lower Fahdene and late Cenomanian-early Turonian Bahloul potential source rocks and ten oil seeps and bitumen impregnations collected from faulted Mesozoic and Cenozoic outcrops and mine boreholes located around three extrusive salt structures of Ech-Cheid, Fej Lahdoum, and Boukhil belonging to the Triassic salt domes zone of northern Tunisia allowed us to draw the following main remarks:

Rock–Eval pyrolysis highlighted fair to good quality of the Albian lower Fahdene (means TOC: 0.90 wt.%, HI: 180 mg HC/g TOC, and PP: 2.00 mg HC/g rock), and good to excellent quality of the Cenomanian–Turonian Bahloul Fms (TOC up to 8.1 wt.% with means TOC: 3.5 wt%, HI: 458 mg HC/g TOC, and PP: 20 mg HC/g rock reaching up to 67.43 mg HC/g rock). These source rocks were deposited in a deep marine basin marked by the presence of subsiding zones and paleohighs where OM accumulation and preservation were controlled by the interplay of global (eustatism, bioproductivity) and local factors among them subsidence and synsedimentary faults in tilted blocks associated with Triassic salt tectonics. The highest OM contents coincide with subsiding zones (grabens and half-grabens) located in the southern flanks of Triassic salt diapirs.

The basin architecture and the variable degrees of subsidence controlled the different maturity levels of the Fahdene and the Bahloul Fms between late diagenesis and the late oil window.

GC and GC–MS analysis of oil seeps and bitumen impregnations showed that these have been generated from mature and early-mature marine argillaceous and marl-carbonate source rocks deposited in oxic to suboxic and suboxic to anoxic environments with a normal salinity water column.

Biomarkers comparison and the depositional environment identification deduced from both extracts and oil seeps allowed the recognition of three oil families (I, II, and III). Families I and II correlated with the Albian lower Fahdene and the Cenomanian–Turonian Bahloul source rocks respectively, while family III is considered a mixture of hydrocarbons generated from both sources.

The spatio-temporal oil seeps distribution and their associated tectonics suggest several faults of NW–SE, N-S, E-W, and NE-SW trendings which facilitated oil migration from these source rocks to favorable upper Cretaceous and Miocene reservoirs.

Regarding these results, we state that Cretaceous petroleum systems are active in the study area. The maturation, expulsion, and migration have been realized but the trapping and preservation are the most critical processes. Future petroleum exploration should focus on research of aborted diapiric and anticline structures which could be found in inter-diapiric zones of north-western Tunisia, the Sahel basin, and the Pelagian block in eastern Tunisia.