Geochemical characteristics and oil–oil correlation of the upper Cretaceous oils from the Iranian part of the Persian Gulf Basin

The Cenomanian Sarvak oil reservoirs are distributed over large areas of the Persian Gulf basin. The purpose of this study is analyzing the geochemical characteristics of the Sarvak oil reservoirs and their inter-relationships in the Persian Gulf, classification of the Sarvak oil samples and investigation of the possible causes of the genetic difference in oil families. In the previous studies, limited samples of Sarvak oil reservoir in scarce oilfields were studied individually and local interpretations are made accordingly. The current study employs a more complete set of geochemical from the Iranian part of Persian Gulf and regional interpretations are drawn. To achieve this goal, the geochemical data of 41 oil samples from 10 oilfields were collected and assessed based on gas chromatography (GC), gas chromatography–mass spectrometry (GC–MS), and stable carbon isotope analysis. It was demonstrated with the evaluations that the oils accumulated in the Upper Cretaceous Sarvak reservoirs in the Persian Gulf basin originate from different source rocks. The oil samples are genetically classified into four oil families based on the similarities and differences of parameters related to the depositional environment-dependent parameters using hierarchical cluster analysis (HCA), star diagram, and stable carbon isotope diagram. The source rocks were mainly deposited in anoxic marine carbonate environments. The thermal maturity of the oils was evaluated using steranes and trisnorhopanes. Oil families 2 and 4 (located at the center of the Persian Gulf) have the highest thermal maturity compared to the other samples; in contrast, oil family 1 (located at the west of the Persian Gulf) has the lowest thermal maturity. The possible source rocks of oil family 1 and family 3 (located at eastern Persian Gulf) using C28/C29 steranes are the upper Cretaceous successions; in contrast, the possible source rocks of oil families 2 and 4 are the upper Triassic and Lower Jurassic formations. Results of the study show a high similarity between the oils of families 2 and 4, which are located at the center of the Persian Gulf; these results also recognize the significant difference between these two oil families and oil families 1 and 3. The significant issue raised in this study is to find out the reason for this difference. The structural analysis of the central Persian Gulf shows that huge vertical faults created by salt domes intrusion provided the migration pathways for trapping oil in Sarvak reservoirs. The oils of the Surmeh, Fahliyan, and Dariyan reservoirs have migrated upwards through these faults to be trapped in the Sarvak Formation across the central Persian Gulf.


Introduction
The Persian Gulf basin and the surrounding coastal areas comprise about 60% of the world's crude oil reserves and 40% of the world's gas reserves (Alsharhan 2014;Baniasad et al. 2021). The tectonic features and the presence of geological structures, as well as the presence of layers rich in organic matter, thick carbonates of porous and permeable layers and the placement of extensive shaly and seal evaporite beds on them, have led to the formation of such huge hydrocarbon reserves (Pollastro 2003;Bordenave and Hegre 2010). The Sarvak Formation together with the Asmari Formation are the host for the largest crude oil reserves in this region. Formerly, various geochemical studies have been conducted in the Persian Gulf region. Rabbani et al. (2014) classified 33 oil samples from different reservoirs of the Persian Gulf region into four oil families based on principal data and biomarker review, which are given as follows: Oil family 1 includes the Jurassic to Lower Cretaceous oil reservoirs in the Doroud, Abouzar, Kharg, and Forouzan oilfields in the northwest of the Persian Gulf region that originated from the Jurassic source rocks and formed in an anoxic marine environment, oil family 2 includes the Jurassic to Lower Cretaceous oil reservoirs in the Balal, Reshadat, Resalat, and Salman oilfields in the central Persian Gulf that originated from the Jurassic source rocks and formed in the dysoxic to oxic depositional environment, oil family 3 includes the Cretaceous to Tertiary oil reservoirs in the Soroosh, Nowrooz, Doroud, Abouzar, Kharg, and Bahregansar in the northwest of the Persian Gulf that likely originated from the Cretaceous source rocks, and oil family 4 is the upper Cretaceous oil reservoirs in the Sirri E, Sirri D, Sirri C, Sirri A, Reshadat and Resalat oilfields in the east of the Persian Gulf that probably originated from the middle Cretaceous source rocks. Alizadeh et al. (2017) studied the oil samples from the Jurassic to Cretaceous reservoirs. They divided the samples into two oil families. Oil family 1 includes the Jurassic oil reservoirs in the west of the Persian Gulf, and oil family 2 represents the Cretaceous oil reservoirs in the east of the Persian Gulf. Mashhadi and Rabbani (2015) collected six samples from the Sarvak reservoirs and thirteen samples from the other reservoirs in the east of the Persian Gulf. They presented two separate oil families. The five samples of the Sarvak reservoirs fall into oil family one indicating their sources are probably the Ahmadi member, the Gurpi, and Kazhdumi Formation. The noteworthy point in these studies is that the samples have been selected from reservoirs belonging to different periods. Therefore, the oil-oil correlation has not been studied specifically in the Cenomanian Sarvak oil reservoirs in the Persian Gulf. The Sarvak Formation was not continuously expanded on the Persian Gulf and has a gap in the region between the center and west of the Persian Gulf (Rabbani 2013). Due to the discontinuous expansion of the Sarvak Formation and the existence of structural features such as giant salt domes, folds, and faults, it is essential to investigate the continuity of the Sarvak reservoirs and the oil-oil correlation. Considering that this issue has not been investigated yet, in this study, we are looking for the answer. Therefore, if the oils are not compatible and the reservoirs are not linked, its cause should be investigated in the future studies and the source of the oils should be determined. The oil-oil correlation method has been applied to identify petroleum systems and reservoir compartments, which increase productivity and reduce exploration and production costs. In this study, the Sarvak oil reservoirs in the Persian Gulf are grouped and their origin is discussed. Also, the reason for the genetic similarity of the oils from the Sarvak reservoirs with the older reservoirs including the Dariyan, Fahliyan, and Surmeh in the central part of the Persian Gulf has been determined by using the evaluation of possible factors. One of the main applications of the present study is to identify the oil fields in the Persian Gulf basin, in which their Sarvak oil reservoirs are linked or have an oil of the same origin. Accordingly, it is possible to predict the location of future wells and increase production by the geochemical model of these fields.

Geological setting
The Persian Gulf sedimentary basin is located in the eastern part of the Arabian Shield, where the Arabian plate subducts beneath the Eurasian plate. This basin is restricted in the north and east by the folded Zagros region and in the west and south by the Arab shield. In addition to the Persian Gulf, this region includes the Oman Sea and the sedimentary basin of the Zagros orogeny foredeep (Konyuhov and Maleki 2006). The sequence of the sedimentary layers in the offshore Persian Gulf and onshore Zagros folded zone developed from the Precambrian to Quaternary (Ghazban 2007). The Persian Gulf basin comprises a Miocene-Recent sedimentary basin that was formed in reaction to a continuous collision between the Arabian shield and the Eurasian plate (Sepehr and Cosgrove 2004;Hessami et al. 2006;Allen and Armstrong 2008).
The relationship between sedimentary basins (e.g. Khavari et al. 2009;Arian et al. 2012;Arian and Aram 2014;Ehsani and Arian 2015;Aram and Arian 2016;Kadkhodaie and Kadkhodaie 2022a, b) and basement faulting (e.g. Arian 2012;Nouri et al. 2013;Nouri and Arian 2017;Nabilou et al. 2018;Mansouri et al. 2017Mansouri et al. , 2018 indicates the role of faults in the control of sedimentary basins in Iran. In terms of lithofacies, especially the role of tectonics, the Iran sedimentary basin is divided into several large tectonic-stratigraphic units (Arian 2015;Razaghian et al. 2018;Taesiri et al. 2020). In the study area, the Persian Gulf as a peripheral foreland basin has been affected by blind faults and their branches. They have been formed and developed by the Arabian-Eurasian plate convergency.
Within Albian-Cenomanian, the Persian Gulf region has been recognized by extensive intrashelf basins in shallowwater carbonate platforms. The Sarvak Formation was formed on a carbonate platform during the Albian to Turonian age and developed along the Zagros, Dezful embayment, and Persian Gulf basin. (James and Wynd 1965;Motiei 1993).
The sediments of the formation in the type section (Tange Sarvak) reach a thickness of about 822 m and consist of two main facies: first, a massive limestone of the shallowwater environment (neritic zone), including euphotic macrofauna (such as algae, rudist, gastropods, pelecypods) and benthic foraminifera, and the second facies is the thinbedding argillaceous limestone from deeper marine characterized by pelagic fauna (Oligostegina, Globigerina, etc.) (Motiei 1993). The contact of the Sarvak Formation with the upper part of Kazhdumi shales is gradational. In contrast, the upper border of this formation with the Gurpi Formation is clear and accompanied by an erosion zone in the type section (Tang-e Sarvak). In the Persian Gulf and Coastal Fars, the Laffan Shale separates the Ilam and Sarvak formations with characteristic peaks in Gamma logs.
In the study area, the Sarvak Formation is divided into the Mishrif, Mauddud and Ahmadi members (Fig. 1). These members are comparable and named from Mishrif, Ahmadi, and Mauddud formations in Iraq (Owen and Nasr 1958). The name "Mishrif member" referred to the limestone observed below the unconformity between the Sarvak formation and the Laffan shale. The Mishrif member is composed of micritic, skeletal, and reefal argillaceous limestone with interbedded marl and shale. This member has diverse components in different sections including rudist reef complex, coral, rudist bioherms, rare planktonic, and benthic foraminifera (El-Naggar and Al-Rifai 1972). In the study area, the reservoir zone is the upper part of the Sarvak Formation (Mishrif member).

Materials and methods
A total of 41 samples from the 10 oilfields in the west, central and east of the Persian Gulf basin were collected (Fig. 2) and studied based on geochemical experiments. First, the oil samples were decomposed into different hydrocarbon fractions by liquid chromatography. The main part of liquid column chromatography is the stationary phase, which is composed of solid material with the property of absorbing fluids. The adsorbent solids in this study are silica and alumina powders. Oil and extractable organic matter (EOM) were separated into hydrocarbons and non-hydrocarbon such as saturate, aromatic and resins fractions. The saturated, aromatic, and resin fractions were, respectively, dissolved by n-hexane, benzene, and methanol solvent (Baniasad et al. 2016). The excess of each solvent is removed from the sample using a rotary evaporator.
The n-alkalkanes, pristanes and phytanes in the oil composition were measured by the Varian-CP-3800 gas chromatography with 5 CB CP-Sil capillary columns (25 µm × 25 m) (Fig. 3). The GC analysis was performed at the Research Institute of Petroleum Industry (RIPI Lab) ( Table 1).
Gas chromatography with mass spectrometry (GC-MS) is applied for the analysis of biological markers that have been used in correlation studies and in the assessment of the thermal maturity of the oils and extracts. The biological markers which are primarily used in this study are steranes and triterpanes ( Table 2). The main sources of steranes and triterpenes are sterols in the cell membrane of organisms including higher plants and algae (overview in Mackenzie et al., 1983). The steroids or sterols during diagenesis and catagenesis are degraded and turn into steranes and triterpanes. The hopanes are triterpene compounds (pentacyclic), and they are classified as aliphatic hydrocarbons. The source of this compound in living organisms is the membrane component of prokaryotic cells such as phototrophic cyanobacteria and heterotrophic bacteria (Ourisson et al. 1987).
The mixture to be analyzed is injected with an injection chamber into the Agilent 7890-A gas chromatograph with an Agilent 7883-B automatic sampling (available in AGH University of Science and Technology), where the various compounds are separated according to the speed at which they move through the gas chromatographic column contains molten silica capillary (60 m × 0.25 mm id) with 95% Methyl/5% Phenylsilicone phase (Baniasad et al. 2016).

Fig. 1
The Permian-Quaternary lithostratigraphic column in the Persian Gulf was modified after Ghanadian et al. (2017) and Mohammadrezaei et al. (2020) The compounds are carried with Helium. The decomposed sections of hydrocarbons come out of the chromatographic column and arrive at the ion chamber, respectively. At this stage, the separated compounds lose electrons and become + 1 ions. These components are then separated from each other using a magnetic field due to the difference in mass-to-charge ratio (m/z). Finally, the amount of separated ions is measured by the detector. The values of the stable carbon isotope of hydrocarbons fraction were calculated by the mass spectrometer Finnigan Delta Plus device with the standard of Pee Dee Belemnite (PDB) and ± 0.2 ‰ accuracies (Table 1) (Baniasad et al. 2016).

Oil-oil correlation
One of the problems in using geochemical parameters to analyze oil-oil correlation is the identification of factors affecting the biomarkers including thermal maturity, type of organic matter or microbial degradation. The 20S/ (20S + 20R) steranes ratio is sensitive to thermal maturity, the C 27 , C 28 , C 29 regular steranes are affected by the type of organic matter and some other parameters such as Dia/ (Dia + Reg) steranes and Ts/(Ts + Tm) are affected by the thermal maturity and the sedimentary environment's conditions. Therefore, in this study, different parameters were employed for oil-oil correlation. The biomarker parameters are usually more important than the bulk parameters of the oil in the process of determining the oil-oil correlation (Peters et al. 2005). Because they are more resistant to diagenetic processes and have more accurate genetic information about the origin of the oil.

Statistical study
Hierarchical cluster analysis (HCA) is one of the statistical methods to examine the similarities and differences in the characteristics of the oil samples. In this method, the distance between variables in the statistical population is enumerated and compared with each other. Thus, the relationship of the samples is determined using a dendrogram (Ward 1963). Then, the samples are grouped, if the parameter values have affinities. The HCA statistical study was performed using MATLAB software based on 22 geochemical parameters. Since the oils are classified based on the origin and type of organic matter, the biomarker parameters that are sensitive to thermal maturation were not used. According to this diagram, the oils of the Sarvak reservoirs in the Iranian part of the Persian Gulf are divided into four oil families (Fig. 4).
Oil family 1 includes the oils of the Bahregansar and Hendijan oilfields in the west of the Persian Gulf region. Oil family 2 includes the RD-A, RE-A, NT-C, HD-C, and BL-A samples from the Reshadat, Resalat, Nosrat, Hendijan The star diagram of the samples is plotted using 11 parameters that depend on the sedimentary environment and the type of organic matter. This diagram is a reliable tool for evaluating the oil-oil correlation. As is seen, star diagrams confirm the classification conducted by the HCA method. In the star diagram of oil family 2, a good correlation can be seen between the samples. In addition, the difference in the origin of the samples of oil family 2 with oil families 1 and 3 is quite apparent (Fig. 5). Due to the high similarity between oil families 2 and 4 and also the genetic differences between oil families 1 and 3, the relationship between the oil families 2 and 4 is an issue that needs to be investigated. The variation in the number of stable carbon isotopes in hydrocarbon fractions depends on the sedimentary environment conditions. Therefore, the stable carbon isotope diagram is an applied method for comparing the genetic similarity and differences in crude oils (Galimov 1973). The trend of stable carbon isotope values of the hydrocarbon fractions in the Galimov diagram suggests the similarity of oil families (Fig. 5).

Depositional environment
The amount of pristane and phytane molecules in the oil composition is one of the most important detectors of the redox conditions in the paleoenvironment. The process of converting the phytyl chain from biological organisms (bacteriochlorophylls sulfur bacteria) to phytol and then phytan takes place in marine/lacustrine anoxic environments, in sedimentary environments with oxic water, the phytyl is oxidized and produces phytenic acid. Phytenic acid is converted to pristene and then to pristine (Powell and McKirdy 1973;Peters et al. 2005). Due to this issue, the value of the Pr/Ph ratio in the oil composition is directly related to the Eh of the depositional environment and inversely related to its pH. The oils generated from the reducing depositional environment have Pr/Ph ratio values less than one and the oils generated from the oxic depositional environment have Pr/Ph values greater than three (Didyk et al. 1978). Also, values of this ratio between 1 and 3 indicate that the oil sources are dysoxic depositional environments. The values of this ratio in the oil samples are between 0.09 and 1.2. Thus, the oils of the Sarvak reservoirs in this region originated from the source rocks that formed in the anoxic marine depositional environment with low Eh and high pH to marine depositional environments with moderate Eh and pH. As is seen in Fig. 6, the depositional environments of the source rocks of all samples are in the range of reducing marine environments. In addition, it is found that the reducing conditions of the sedimentary environment of the source rocks is in the range of anoxic belonging to oil family 3 to dysoxic conditions belonging to oil family 1. The high salinity of water  Family 4 BL-S1 B L-S2 RE-S1 SL-S1 in the depositional environments of the source rocks is one of the reasons for the high amount of Gammaceranes in the composition of the crude oils (Sinninghe Damsté et al. 1995). Therefore, the Gammacerane index is one of the indicators for the depositional environments' water salinity. In the oils produced from marine environments with normal salinity, the Gammacerane index is less than 0.1, and it is between 0.1 and 0.2 in the oils produced from the low-salinity marine environments (Song et al. 2017).
The Gammacerane index values in the mentioned samples are from 0.04 to 0.18, which indicates the source rocks deposited in the marine environments with normal to low salinity. Using the plot of the Gamm index versus Pr/Ph, the salinity and stratification of the depositional environment water column were determined (Fig. 7).
Accordingly, the samples of oil family 1 are generated from a non-stratification depositional environment with normal salinity. And source rocks of oil families 2, 3 and 4 are formed in the marine environments with low salinity and stratification (Table 3).The Dibenzothiophene and Phenanthrene aromatic biomarkers are used to evaluate the depositional environment and to determine the source rocks facies. The low values of the DBT/P ratio (less than 1) indicate the shale source rocks and high values (greater than 1) show the carbonate source rocks (Hughes et al. 1995). The values of the DBT/P ratio in oil families are variable. In oil family 1, the DBT/P ratio is low falling in the range of 0.34 to 0.9, while in oil families 2, 3 and 4, its values vary from about 1-3.16. As is seen in the plot of DBT/P versus Pr/Ph, the origin of oil family 1 is shale and the combination of shale and carbonate sediments and the origin of oil families 2, 3, and 4 are the carbonate-marl source rocks (Fig. 8).
The ratio of tricyclic terpanes with different carbon atom numbers is a practical parameter for identifying the sedimentary environment of the source rock and the organic matter type (Safaei-Farouji et al. 2022). Usually, the oils derived from the carbonate source rocks have a high C 22 /C 21 tricyclic terpanes ratio and a low C 24 /C 23 tricyclic terpanes ratio (Peters et al. 2005). Due to this fact, the plot of C 22 /C 21 tricyclic terpanes versus C 24 /C 23 tricyclic terpanes is used to determine the source rock facies of oil families (Fig. 9). In this diagram, oil families are clearly separated from each other. By observing the results obtained from the depositional environments study, it is concluded that the source rocks of oil family 1 have differences with oil families 2 to 4 in terms of the lithology, type of organic matter, redox conditions, salinity and water column stratification of the depositional environment (Table 3).

Maturity
The biomarkers used to assess thermal maturity are usually also affected by depositional environment conditions and do not provide a precise interpretation of hydrocarbon maturation. Hence, the different parameters of steranes, triterpanes and triaromatic steroids were used to calibrate their results on oil maturity. In the maturation process of complex geopolymers, the molecular structure changes with the increase in temperature and the passing of time (Khalil Khan et al. 2022). Accordingly, the amount of degraded molecules is directly related to the hydrocarbon thermal maturity. The biological composition of the sterol molecule (R side-chain at C-20) is unstable to heat, and it becomes a stable compound (S side-chain at C-20) with increasing thermal maturity (Mackenzie et al. 1983;Beaumont et al. 1985). This process increases the 20S/(20S + 20R) ratio at C 29 steranes from 0 to 0.55 during the catagenesis stage (Seifert and Moldowan 1986). The variation of C 29 ααα20S/ (20S + 20R) ratio values in the studied samples is slight in the range from 0.34 to 0.52. The lower resistance of Tm (17α-22,29,30-trisnorhopane) to thermal cracking than Ts (18α-22,29,30-trisnorhopane) decreases the concentration of Tm and increases the concentration of Ts with increasing temperature until the concentration of Tm in the hydrocarbon composition reaches zero at the beginning of the oil generation window (Seifert and Moldowan 1978). In the process of substitution of Tm with Ts, the clay minerals play the role of catalyst (McKirdy et al. 1984). In oils produced from shale source rocks, the Ts/(Ts + Tm) ratio can be increased due to the presence of clay. Therefore, the Ts/ (Ts + Tm) ratio is a useful index for assessing the maturity of oils produced from carbonate source rocks. The values of Ts/(Ts + Tm) ratio in oil family 1 are less than 0.56, in oil family 2 are range from 0.34 to 0.63, in oil family 3 are less than 0.34, and in oil family 4 are in the range of 0.47 to 0.77. Accordingly, oil family 3 located in the east of the Persian Gulf has the lowest thermal maturity and the oil families 2 and 4 located in the center of the Persian Gulf have the highest thermal maturity. The chemical reaction of converting steranes to diasteranes depends on three factors in the depositional environment, including temperature, clay content and pH (Peters et al. 2005). As a result, the diasteranes/ steranes ratio increases with increasing thermal maturity. Also, this ratio is high in hydrocarbons produced from shaly depositional environments (Peters et al. 1990). Therefore, C 27 Dia/(Dia + Reg) ratio is used along with the C 29 ααα20S/ (20S + 20R) ratio to determine the thermal maturity of oils.
The variation of C 27 Dia/(Dia + Reg) ratio values in the composition of the mentioned oils is almost large and its range is from 0.23 to 0.76. The triaromatic steroids are one of the main biomarkers related to thermal maturity. Therefore, the TA(I)/ TA (I + II) ratio is used as an oil maturity indicator. With increasing temperature, long-chain configurations of triaromatics steroids are degraded to short-chain aromatics due to the sensitivity of this molecule to thermal cracking (Beach et al. 1989). Therefore, thermal maturity is associated with an increase in the TA(I)/TA (I + II) ratio. The total of C 20 and C 21 triaromatics are used as TA(I) and the total of C 20 , C 21 , C 26 , C 27 , C 28 and C 29 triaromatics are used as TA(II) (Peters et al. 2005). The variation of this ratio in the samples is large ranging from 0.09 to 0.56. These values are less than 0.16 in oil families 1 to 3, while in oil family 4 it reaches 0.56 indicating the higher maturity of this oil family. The thermal maturity of the oil families is shown in the diagram of C 29 ααα20S/(20S + 20R) versus Ts/ (Ts + Tm) ratio and C 29 ααα20S/(20S + 20R) versus C 27 Dia/ (Dia + Reg) (Fig. 10). As is seen, the thermal maturity of the Fig. 8 The plot of DBT/P ratio versus Pr/Ph to determine the source rock facies of oil families Fig. 9 The diagram of tricyclic terpanes to indicate lithology of oil family's source rocks oil families falls in the category of mature oils (Fig. 10). In addition, it is found that the thermal maturity of oil family 3 belonging to the east of the Persian Gulf was less than the other three oil families, oil family 2 along with oil family 4, that produce from the Jurassic and older source rocks have the highest thermal maturity (Table 3). This study shows that the samples whose thermal maturity has been detected beyond the oil generation window belong to oil families 2 and 4 located in the center of the Persian Gulf and have different origins from the other samples.

Source rock's age
The source rock's age is estimated using the C 28 and C 29 regular steranes. The ratio of C 28 /C 29 steranes to the age of the source rock is inversely related. The high value of this ratio in the composition of crude oil indicates the younger source rock and vice versa (Grantham and Wakefield 1988).
In the C 28 /C 29 Steranes versus the %C 28 Steranes diagram, the oil families of the Sarvak Formation reservoirs can be distinguished based on the source rock's age. The origin of oil families 2 and 4 is older than the other two oil families and is related to the Triassic to Jurassic sediments. The origin of oil family 1 and 3 oils is also estimated as Cretaceous sediments (Table 3). In addition, oil family 3, in the eastern Persian Gulf fields, has the youngest origin among the studied samples. The age of the source rock of oil family 3 is estimated as middle Cretaceous sediments (Fig. 11).

Tectonics activities and oil migration
The  (Sharland et al. 2001;Konyuhov and Maleki 2006). Accordingly, this case is rejected. Therefore, to understand the reason for the similarity of the source of oil families 2 and 4, it is necessary to review the tectonic conditions and structural characteristics of the region. One of the influential factors in petroleum systems is the tectonic characteristics of the sedimentary basin (Ehsan et al. 2021). In the study area, the compressive (1) A set of folds with a high slope and a north-south trend, (2) A set of folds with a northwest-southeast trend along with the sinistral strike-slip fault (Stern 1985). In general, the Phanerozoic sequences in the north of the Arabian Shield are affected mainly by the North-South folds and have large anticlines and narrow synclines (Beydoun 1991). The main structure of the Persian Gulf basin is steep-slope folds with a 7° to the northwest and folds with a lower slope of about 3° to the southeast. The asymmetry of the folds is attributed to the thrust faults with the northwest trend (Ziegler 2001 bot and Alavi 1996). Observations indicate the presence of these salt diapirs in areas of the Persian Gulf, the Sea of Oman, and the Zagros frontal basin, but they are absent in the north-south Arabian arches (Memarzia 2004) (Fig. 12).
Using the results of seismic and field studies, Sherkati and Letouzey (2004) found the relationship between salt domes and vertical faults in the center of the Persian Gulf. The salt domes of the center of the Persian Gulf have created huge anticlines such that these anticlines have created large vertical faults. Also, these normal faults have created small synclines (Hassanzadeh et al. 2018) (Fig. 13). 3D seismic data were acquired in the field location. The survey covered a total area of approximately 1050 km 2 . The quality of 3D post-stack migration data is reasonably good and faulted graben structures over the Reshadat field can be clearly seen. By studying the seismic profiles of the Lavan province, it turns out that the huge vertical faults range from the Upper Triassic successions to the Santonian Ilam Formation (Fig. 13).
It can be concluded that family 2 oils are produced from the Jurassic source rocks. They crossed the anhydrite Hith barrier by the faults in this region and were finally trapped in the Sarvak reservoir. The noteworthy point is that according to the available evidence, it was concluded that the hypothesis of hydrocarbon migration by faults in the central oilfields of the Persian Gulf is more probable, but the rest of the hypotheses cannot be definitively rejected with the available information.

Conclusions
The current study employs a complete set of geochemical from the Iranian part of Persian Gulf to draw regional interpretation of geochemical data. For this purpose, a Fig. 12 The giant salt dome is observed in the SW-NE stratigraphic section of the Persian Gulf region. Apart from basement faults, many normal faults occurred in the study area due to the upwards movements of the salt diapir. 1: Basement rock, 2: Hormuz salt, 3: Sand-stone, 4: Anhydrite/gypsum, 5: Dolomite, 6: Dolomitic limestone, 7: Limestone, 8: Marl-limestone, 9: Conglomerate (modified from Edgell 1996) total of 41 oil samples from 10 oilfields were collected and assessed based on gas chromatography (GC), gas chromatography-mass spectrometry (GC-MS) and stable carbon isotope analysis. Considering the results of this study, the followings conclusions are drawn.
• The oil samples of the Sarvak reservoirs from ten oilfields in the western, central and eastern parts of the Persian Gulf were evaluated using hierarchical cluster analysis (HCA), star diagrams and the Galimov isotopic diagrams. The oils were divided into four families based on characteristics of their origin. • The Sarvak reservoirs oils in the western Persian Gulf (oil family 1) have a Cretaceous source rock formed in a shaly sedimentary environment with dysoxic conditions, normal salinity, no stratification and medium maturity in the oil generation window. • The Sarvak reservoirs oils in the central Persian Gulf (oil families 2 and 4) have the Jurassic and earlier source rocks formed in carbonate-marl sedimentary environments with anoxic to dysoxic conditions, low salinity and stratification and high thermal maturity. • The Cretaceous rocks deposited in a carbonate-marl environment with anoxic conditions, low salinity and stratification and low thermal maturity charge the Sar-vak reservoirs in the eastern Persian Gulf basin (oil family 3) • It was found that oil families 2 and 4 have more mature and older oils than families 1 and 3. • The geochemical differences in the oils are attributed to the presence of normal vertical faults. • The migration of hydrocarbons from the Surmeh oil reservoirs at a depth of about 2400 m to the Sarvak oil reservoirs at a depth of about 1000 m has occurred through these faults.