Introduction

The Persian Gulf, a small sea adjacent to the Indian Ocean, lies between Iran and the Arabian Peninsula (see Fig. 1). The Persian Gulf and its coastal parts contain the major quantities of crude oil and natural gas, approximately 715 billion barrels of crude oil (2/3 of the world’s proven oil reserves) and 2462 tcf of gas (1/3 of the total verified world gas reserves) (Rabbani 2014; Baniasad et al. 2017). In this area, the presence of many significant regional caprocks, considerable source rock beds, great carbonate reservoirs, huge anticlinal traps and continuous sedimentation are the main factors turning this gulf into an excellent region for hydrocarbon accumulations (Rabbani et al. 2014). One part of this region is the Fahliyan Formation in the NW of the Persian Gulf, and many significant oil reservoirs were discovered there in the last 50–60 years (Soleimani et al. 2017). Thus, the presence of widespread reservoir development in combination with the organic-rich deepwater Garau formation among other source rocks turned this formation into an important target for hydrocarbon exploration (Adabi et al. 2010).

Fig. 1
figure 1

Map showing the Northwest Persian Gulf area (Southwest Iran) studied

Full size image

The stratigraphic and sedimentary environments of the Fahliyan Formation were reported by several authors including James and Wynd (1965), Shakib (1994), Moallemi (2000). In recent facies analysis, it was stated that the Fahliyan Formation in some sections of Southwest Iran is composed of both, shallow and deep marine facies; restricted marine barriers, and open marine shallow facies (deposited on a carbonate shelf platform), and pelagic and calciturbidite deep marine facies (deposited on the intrashelf basin) (Kondroud and Lasemi 2008).

However, the geology of this formation is well described (see Table 1) (Kavoosi et al. 2006; Jamalian et al. 2010; Feghhi et al. 2012; Abyat et al. 2012, 2014; Mahbaz et al. 2012; Shakeri and Parham 2013; Jamalian and Adabi 2014; Soleimani et al. 2017), considerable uncertainty related to the maturity and quality of source rocks still exists which may affect on the reliability of geochemical models. Consequently, this study focuses on characterizing the Fahliyan Formation with regards to the depositional environment, organic matter, source rock, and thermal maturity in two fields in the Iranian Fars sector. Hence, a detailed organic geochemical analysis with bulk geochemical parameters for the Fahliyan Formation oils was performed here.

Table 1 Summary of some previews works about the geochemistry of the Fahliyan Formation
Full size table

Geological setting

Fahliyan Formation within the surface section of the Kuh-e Siah was overlaid by the Lower Cretaceous Gadvan Formation with a conformable contact but it unconformably covers the Upper Jurassic Hith Formation (see Fig. 2) (Soleimani et al. 2017). The Kuh-e Siah anticline can be seen within the Fars Salient in the south of the Zagros fold-thrust belt (ZFTB) and is composed of a sequence of heterogeneous recent Neoproterozoic–Phanerozoic sedimentary cover strata with a thickness of about 7–12 km (Aubourg 2004). ZFTB is the re-shaped form of the Zagros sedimentary basin. According to the current positions, this basin was stretched out over the northeast of the Afro-Arabian continental margin which develops the Zagros orogeny from the closure of the Neo-Tethys due to three geotectonic events including the sliver emplacement of oceanic crust over the Afro-Arabian continental margin, Afro-Arabian continental collision with the Iranian plates, and subduction of the Neo-Tethyan oceanic crust beneath the Iranian plates (Sherkati et al. 2005; Bahroudi and Koyi 2003). Generally, the ZFTB is extended by about 2000 km from the southeast of Turkey through the north of Syria and northeast of Iraq to southwestern Iran. Meanwhile, it is one of the most essential tectonic units in Iran which has a length of greater than 1500 km and 100–300 km in width (Abyat et al. 2012).

Fig. 2
figure 2

Lithostratigraphic chart of the Mesozoic of the Zagros Basin (Alavi 2007)

Full size image

Zagros Orogen is composed of three separate parallel tectonic zones, such as Zagros imbricate zone (ZIZ), Urumieh Dokhtar magmatic assemblage (UDMA) and Zagros fold-thrust belt (ZFTB). ZFTB as an external part of the orogen extends parallel to the southwest of ZIZ by 300 km in width which contains some salients and recesses from northwest to southeast, such as Kirkuk recess in northern Iraq, Lorestan salient, Dezful recess and Fars salient in southwestern Iran (Alavi 2007, Kamali et al. 2013; Rbbani et al. 2014). From west, east, northeast and southeast, the Fars zone has been surrounded by Kazerun Fault, Zendan Fault, High Zagros Fault and Persian Gulf coastal line, respectively (Sabouhi et al. 2009). This zone is mainly characterized by the presence of 15–20 km anticlines which was developed from bending mechanism on the Hormuz Salt. However, these anticlines have been divided into five different trends by thrust faults with the presence of salt domes (Bordenave 2003). The impact of these salt domes on the anticline can be used as the most important structural features in this region. Even, the trapping style of hydrocarbon in this region varies to that formed in Embayments and regions because its source rock developed more gas and less oil accumulations (Schwarzbauer et al. 2000; Amijaya et al. 2006).

Samples and methods

Three crude oil samples were collected from KG-031 well in ‘KG’ oilfield and F9A-3H and F15-3H wells in ‘F’ oilfield in the northwest of the Parisian gulf for analysis in this study (see Fig. 1). The density (API) of oil samples was measured at 15.6 °C (60 °F) using an Anton Paar density meter (Anton Paar DMA5300M). In addition, the kinematic viscosity of the crude oils was measured at three different temperatures (10 °C, 20 °C and 40 °C) using VST-2400 viscometer.

Furthermore, selected crude oils were subjected to a series of analytical tests (Sulfur content, nickel and vanadium ratios, pour points, cut points and ‘SARA’ = Saturate, Aromatic, Resin and Asphaltene fractionation). The sulfur, carbon, hydrogen and nitrogen contents of oil samples were measured using a LECO CHNS-932 analyzer at 1000 °C burning temperature in the presence of oxygen. The nickel and vanadium ratios were measured using atomic absorption spectrophotometry. Thus, 2–3 g of each sample were treated overnight with an equal weight of concentrated sulfuric acid with the purity of 95–99% total mass. After recovering this acid by heating on a hot plate with gradual temperature increase, the samples were ashed with gradually increased temperature up to 450 °C and were dried overnight. The ashed samples were then heated on a hot plate for 10–20 min and 1 ml of concentrated aqueous HCI was added to the solution until it was clear and yellow, and subsequently filtered. The resulting solution was diluted and analyzed for Ni and Va on a Varian spectrum 14.4–30 atomic absorption spectrophotometer.

In the SARA analysis, the asphaltene fraction was precipitated by addition of n-heptane with a purity of 98%. The asphaltene-free samples and the saturate fractions were analyzed via gas chromatography in order to obtain the distribution of alkanes and Pristane (Pri), Phytane (Phy), C17, C18, etc. For conducting the gas chromatography (GC) analysis, we followed the procedures drawn by Schwarzbauer et al. (2000), Amijaya et al. (2006). The asphaltene-free sample was injected into the GC in a heated port linked with a fused-silica cross-linked methyl silicone gum with the instrument specifications and test conditions shown in Table 2. Finally, the complementary geochemical analysis and biomarker finger printing were carried out on of saturate and aromatic fractions of oil samples using gas chromatography–mass spectrometry (GC–Mass) analysis with the instrument specifications and test conditions shown in Table 3.

Table 2 Instrument specifications and test conditions of gas chromatography (GC) analysis
Full size table
Table 3 Instrument specifications and test conditions of gas chromatography–mass spectroscopy (GC–MS) analysis
Full size table

Results and discussion

Hydrocarbon source

Table 4 shows the various measured physical properties of crude oils. The sulfur content and V/(Va + Ni) ratio of the analyzed samples were ranged between 1.32 to 2.24 mol% and 62 to 73 mol%, respectively. According to Lewan (1984), when the Va/(Va + Ni) ratio is greater than 0.5%, it is an oxygen-free environment. Va/(Va + Ni) ratios for the oil samples from the KG-031, F15-3H, and F9-3H wells were 72.5%, 67.7% and 72.3%, respectively. When considering these ratios in combination with the sulfur contents, it can be concluded that all oil samples were formed from a single source rock which deposited in a reducing environment with calcareous lithology as shown in Fig. 3 (Lewan 1984).

Table 4 Physical properties of oil samples
Full size table
Fig. 3
figure 3

V/(V + Ni) ratio versus Sulfur content of analyzed crude oils

Full size image

When plotting sulfur content versus API gravity of Fahliyan oils, in accordance with Mashhadi and Rabbani (2015), it is clear that these oils were generated from a matured source rock containing kerogen type II (see Fig. 4). According to the API standard ratios, the Fahliyan oils can be classified as light to medium oils with the presence of high sulfur contents ranging from 1.32 to 2.24 wt.%.

Fig. 4
figure 4

Cross-plot showing the relation between API gravities and Sulfur contents of the crude oils tested

Full size image

Oil–oil correlations

Bulk properties of the analyzed oil samples indicate that the ‘KG’ oil is a medium oil with an API gravity of 30.4° and the ‘F’ oils are light oils with API gravities ranging from 31.3 to 33.6°, as shown in Table 4. Furthermore, it is clear that the Fahliyan oils consist of different components. Thus, the bulk composition of studied oils is generally dominated by higher concentrations of saturated components (43.39–60.09 mol%) compared to aromatic, resin, and asphaltene compounds (with various ratios from 1.24 to 38.62 mol%) (see Table 5). The ratio of saturated to aromatic hydrocarbon is higher than 1.0 for all samples, and the saturate, aromatic, resin and asphaltene fractions are small with ratios < 70 mol%. Hence, they were buried at shallow to medium depth (Liu et al. 2017).

Table 5 Geochemical data and gross chemical composition of crude oils tested
Full size table

Fahliyan oils extracted from two extracted oil reservoirs were further investigated using cut point analysis. In this way, they were distilled 5% intervals with respect to yield percent of boiling points. When comparing the cut points of these oils, it can be seen that there is a close resemblance in the distribution patterns between the oil samples from F15-3H and F9-3H wells (see Fig. 5). However, the KG-031 oil shows a clear difference from 15% yield onward, which indicates the presence of heavier oil components when compared to the ‘F’ oil. This is true with respect to the weight percent of hydrocarbon fractions and API degrees discussed above.

Fig. 5
figure 5

Comparison distribution of cut points of crude oils tested

Full size image

DHA results were divided into five various groups including paraffines, aromatics, iso-paraffines, naphthenes and olefins (see Fig. 6). As it can be seen, the percentage of paraffinic hydrocarbon from both F15-3H and F9-3H wells was higher than what measured from the ‘KG’ oil. However, the aromatic ratio in ‘KG’ oil is higher compared with the ‘F’ oils. In summary, it can be stated that the Fahliyan oils are mainly composed of paraffinic and iso-paraffinic hydrocarbons with low carbon content.

Fig. 6
figure 6

DHA group type distribution based on light oil fractions

Full size image

Organic matter and depositional environment

Gas chromatographic (GC) results of the analyzed crude oils are shown in Fig. 7 and summarized in Table 6. Generally, the normal alkane distribution patterns can be seen in the range between C8 and C31 while maximum peaks are basically identified between C10 and C14. According to Mobarakabad et al. (2011), it was remarked that alkanes smaller than C8 might be lost during oil sample handling. Specifically, a normal alkane distribution was identified for F9-3H oil (Fig. 7a), which has a Pr/Ph ratio of 0.72; while the pattern distribution of F15-3H oil indicates that the oil is mainly composed of n-alkanes with a low amount of isoprenoids alkane, Fig. 7b. The third crude oil from KG-031 well, however, has a complete distribution of the normal alkanes (Fig. 7c), but its Pr/Ph ratio (0.89) is slightly higher. This normal alkane distribution pattern is a key feature of source rocks containing a high content of marine organic matter input (Peters et al. 2005).

Fig. 7
figure 7

Gas chromatograms of Fahliyan crude oils from ‘F’ and ‘KG’ fields

Full size image
Table 6 GC analysis results for saturate fraction of oils
Full size table

The depositional environment and organic matter source are commonly identified using the Pr/Ph ratio; Pr/Ph ratios higher than 3 indicate oxic deposition with terrigenous organic matter input, and low Pr/Ph ratios (< 1) indicate a highly saline and reducing depositional setting (Hunt 1996; Li et al. 1999). As the Pr/Ph ratios of the Fahliyan oils are less than 0.9, we conclude that the ‘F’ and ‘KG’ oils have been generated in a saline and reducing environment.

From Pr/nC17 versus Pr/n-C18 ratio cross-plots shown on Fig. 8, the maturity, organic matter input and dependent on Tissot and Welte (1978), Peters et al. (2005), depositional environment of the Fahliyan oils were identified. Thus, in combination with the normal alkane distribution discussed above, it can be concluded that non-biodegraded hydrocarbons are present in the Fahliyan Formation. On the basis of having Pr/nC17 and Pr/n-C18 ratios relatively low (ranging from 0.21 to 0.41), the analyzed oils might be originated from marine carbonate source rocks, and deposited in reducing environments with marine organic matter. This is true with what Abdullah and Connan (2002) was reported. Considering the small variance in these ratios, it is clear that these crude oils were generated from a single source rock with a high maturity level.

Fig. 8
figure 8

Pr/n-C17 versus Ph/n-C18 ratio cross-plots for the studied crude oils

Full size image

Based on the concept of Seifert and Moldowan (1980), the ternary C27, C28, and C29 regular steranes diagram was also considered to determine and confirm the depositional environment of the crude oil source rocks (Fig. 9). Clearly, the oil samples from both fields were derived from a single source rock, which was deposited in an open marine environment. The C27, C28, and C29 steranes have approximately the same concentrations in the ‘F’ oils (C27 ≈ 23, C28 ≈ 77 and C29 ≈ 52), and varied concentrations in ‘KG’ oil (C27 ≈ 19, C28 ≈ 81 and C29 ≈ 50). Meanwhile, the C27, C28 and C29 in all analyzed oils have the same concentrations trends, i.e., C28 > C29 > C27.

Fig. 9
figure 9

Ternary diagram illustrating the relative C27, C28, and C29 sterane contents of the studied oil samples

Full size image

In addition, dibenzothiophene/phenanthrene (DBT/P) versus Pr/Ph ratios indicate the lithology of the source rock (Hughes et al. 1995), for instance carbonate rocks have a ratio higher than 1 and shales have ratios less than 1. The analyzed crude oils fall in Zone-1B of the cross-plot, which indicates that the lithology of the source rock is marine carbonate and marl (Fig. 10). However, DBT/P is greater than 1 for the Fahliyan crude oils, this ratio ranges from 1.2 to 2.8, representing the various source rock facies. Higher DBT/P ratios for F15-3H and KG-031 oils thus show higher carbonate content in their source rocks than in case of F9-3H oil.

Fig. 10
figure 10

Pr/Ph ratio versus DBT/P ratio cross-plot for studied oil samples (Seifert and Moldowan 1980)

Full size image

Thermal maturity

For evaluation of oil maturity levels, steranes and hopanes concentrations were analyzed (Table 7). Thus, two plots were drawn, first the C29 ααα 20S/(20S + 20R) versus C29 αββ/(ααα + αββ) ratios, and second the methyldibenzothiophene (MDBT) versus C32 22S/(22S + 22R) ratios as shown in Fig. 11 (Peters and Moldowan 1991; Peters et al. 2005). All oil samples are in the mature oil interval as the C29 ααα 20S/(20S + 20R) and C29 αββ/(ααα + αββ) ratios range from 0.47–0.48 to 0.52–0.57, respectively (Fig. 11a). Although the methyldibenzothiophene (MDBT) ratio of F15-3H oil is lower when compared to the other oils, Fig. 11b also indicates that the source rock of the Fahliyan crude oils is well matured (Peters et al. 2005). Figure 12 expresses the relationship between 20S/(20S + 20R), ββ/(αα + ββ) and 22S/(22S + 22R) for C29 and C32 steranes and oil maturity levels. With increasing maturity, the 20S/(20S + 20R) and ββ/(αα + ββ) C29 sterane ratios increase until equilibrium ratios are reached (Peters et al. 2005). Additionally, the 22S/(22S + 22R) ratio of C32 homohopanes increases during maturation up to 0.6 (Mashhadi and Rabbani 2015). As the measured 20S/(20S + 20R) and ββ/(αα + ββ) for C29 sterane and 22S/(22S + 22R) for C32 homohopanes from the Fahliyan Formation vary from 0.47 to 0.6, it confirms that the analyzed oil are highly mature (Fig. 12).

Table 7 Steranes and Hopanes biomarkers obtained (m/z 217) and Terpanes (m/z 191) measured for the selected oils
Full size table
Fig. 11
figure 11

Cross-plots showing the maturity level of the oil samples studied based on a C29 aaaS/(aaaS + aaaR) versus C29 ββ/(ββ+αα) steranes ratio and b MDBT 2 versus C22S /(22S + 22R) C32 Hopanes ratio (Peters et al. 2005)

Full size image
Fig. 12
figure 12

source rocks and Fahliyan oils

Comparison of the thermal maturity of the studied Cretaceous

Full size image

Furthermore, the Hopane parameters were analyzed to further identify the maturity level (Peters and Fowler 2002). We found that the variation of C30Ts/C30H content in ‘F’ and ‘KG’ field oil is small (ranging from 0.22 to 0.26), Table 7a. The Gammacerane/C30–31 ratio varies widely (from 0.16 to 0.69) and it is less than 1 for all samples studied. Moreover, the Ts/(Ts + Tm) ratio lies between 0.29 and 0.45, which indicates that Fahliyan is a mature oil (Peters et al. 2005).

Oil–source rock correlation

As discussed above, and based on the GC hopane/sterane analysis (see Fig. 13), the oil samples were identified to stem from a carbonate-rich source rock with marine organic matter input, which deposited under marine reducing conditions to at high maturity level. In addition, the relationships between Pr/Ph, C29/C30 hopane, DBT/P, Pr/nC17 and Ph/nC18 illustrate that the carbonate source rock was deposited in a reducing marine environment. Considering the hopane/sterane parameters on the star diagrams, the Fahliyan oils from the two different fields are very similar and show almost the same hopane/sterane ratios (Fig. 13). This also suggests that the analyzed crude oils were formed from the same single source rock.

Fig. 13
figure 13

Steranes (left) and Hopanes (right) parameters of the studied oils

Full size image

Diasterane/sterane ratios are commonly used to distinguish the type of source rock from which the hydrocarbons were generated (i.e., carbonate or clastic), Seifert and Moldowan (1980), Gratzer et al. (2011); low diasterane/sterane ratios indicate anoxic clay-poor or carbonate source rock, while high diasterane/sterane ratios suggest that the hydrocarbon derived from clay-rich source rocks. Furthermore, in some crude oils, high thermal maturity and/or heavy biodegradation results in a high diasterane/sterane ratio (Zumberge 1984; Alavi 2007). In this work, the C27 Dia/(Dia + Reg) versus C29/C30 hopane ratios have been plotted to identify the depositional environment of the oil source rocks (Fig. 14a). It can be seen that the Fahliyan oils have low diasterane/sterane ratios, suggesting that they were formed in carbonate source rocks. C22/C21 and C24/C23 tricyclic terpane ratios can also be used to identify the type of source rock; for shaly source rock the C22/C21 tricyclic terpane ratio is less than 0.5, whereas ratios higher than 0.5 indicate carbonate source rock (Grantham and Wakefield 1988). Thus, the C22t/C21t ratios (ranging from 0.75 to 0.95) versus the C24t/C23t ratios (ranging from 0.29 to 0.47) were plotted in Fig. 14b. Clearly, all oil samples were generated from marl-carbonate source rocks, consistent with the hopane analysis.

Fig. 14
figure 14

Biomarkers cross-plot of a C27 diasterane/C27 diasteranes versus C29 norhopane/C30 hopane ratio (29H/30H), and b C24t/C23t versus C22t/C21t ratios of tricyclic terpanes

Full size image

In order to determine the age of the source rock, C28/C29 regular sterane ratios were examined; ratios < 0.7 indicate Paleozoic and Jurassic ages, while ratios > 0.7 indicate Upper Jurassic to Cretaceous-Tertiary ages (Zumberge 1984). Here, %C28 regular sterane versus C28/C29 sterane ratios ranged from 0.38–0.61 and 18.55–25.87, respectively. Thus, these crude oils accumulated in deeper reservoirs, and originating from late Jurassic or early Cretaceous rocks (Fig. 15).

Fig. 15
figure 15

source rock

C28/C29 versus %C28 regular sterane ratios indicating the age of the

Full size image

Conclusions

Multiple major Fahliyan reservoirs have been identified in the NW region of the Persian Gulf (Adabi et al. 2010; Abedpour et al. 2016; Feghi et al. 2012). However, the origin, source rock and maturity of the oil within this formation are only poorly understood. Thus, in this study, a detailed petroleum geochemical analysis of three selected crude oils from Fahliyan reservoirs in SW Iran has been performed. In this way, it was verified that the hydrocarbon in these reservoirs was generated from the late Jurassic to early Cretaceous. In addition, the oil bulk properties and biomarkers were characterized, and an oil–oil and oil–source rock correlations study was carried out between the three crude oils and the source rock. From this extensive analysis, it is clear that all oils are nonbiodegraded with high maturity, have a high sulfur content and were generated in carbonate source rocks containing kerogen type II. The source rock again was deposited under marine reducing conditions with marine organic matter as the dominant input.