C29 Sterane 20S Research Articles

Paleoenvironment and origin of heavy oil of the lower Cretaceous-Oligocene: a case study

ABSTRACT Many heavy oil wells have been found in the Jilantai shallow depression in the Hetao Basin. The origin of heavy oil in the study area was analyzed comprehensively according to the physical properties and geochemical characteristics of heavy oil. Two sets of source rocks were detected in the Guyang and Linhe groups, in the Hetao Basin. During the Guyang Formation, the differences of sedimentary environments resulted in brackish water sedimentary environment in the south of the study area and freshwater reducing environment in the north of the study area. The high content of boron in the source rocks of Linhe Formation indicates its saltwater environment. By the method of oil source comparison, it is found that the Pr/Ph of the crude oil in Jilantai area and Linhe Formation is lower than 0.50, and the Pr/nC17 is between 0.7 and 3.5, which should come from the source rock of the first segment of the southern moderate lacustrine Guyang Formation. The C29 sterane 20S/(20S+20 R) and C29 sterane ββ/(αα+ββ) parameters indicate that the low maturity of crude oil is the main cause of heavy oil formation. The research on the genesis and geochemical characteristics of Jilantai crude oil indicates that the northern and central depression of the Hetao Basin is a rich area of favorable resources.

Origin, geochemical characteristics and filling pathways in the Shadegan oil field, Dezful Embayment, SW Iran

The Shadegan oil field is one of the fields in the central part of the Dezful Embayment. Little or no geochemical studies have been performed previously in this field. This paper provides valuable information to answer most of the geochemistry ambiguities and issues in this field. Different techniques were used to investigate the genetic types of Asmari and Bangestan reservoirs. Structural characteristics of asphaltenes, biomarker fingerprints, and V/Ni ratio indicates that all oils in the Shadegan field have similar source rock(s) and belong to one oil family. The homologous series of normal alkanes distribution and the absence of 17α(H) 25-hopane reveals that biodegradation has not affected oil samples and planktons/algal or higher plants are dominating organic matters, proved by hopanes/steranes ratio. The Pr/Ph < 1, 0.49 < V/(V + Ni) < 0.81, and homohopanes distribution implied an anoxic condition during source rock deposition. The DBT/Ph, C24/C23 tricyclic terpanes, C22/C21 tricyclic terpanes, C29/C30 hopane, diasterane/sterane ratios suggest that the contribution of clay to source rock was insignificant and source rock has composed of a mix shale and carbonate. Steranes show C29 > C27 > C28 pattern, and the ternary diagram of steranes confirmed that the source rock deposited in the open marine environment and oil samples originated from marine organic matters. All samples have been sourced from a source rock(s) older than the Upper Cretaceous, as shown by the oleanane ratio. The Kazhdumi Formation is the primary source rock in this field, and some contributions from other source rocks might have occurred. In general, samples indicate maturity before the peak of the oil window in which the Bangestan samples have lower maturity regarding the Asmari samples based on aromatic and saturate maturity parameters. The tracing of oil filling pathways by isopleth maps of 4-/1-MDBT and C29 sterane 20S/(20S + 20R) ratios revealed that each reservoir had been charged from several directions. Although the Upper Asmari and Bangestan reservoirs have been charged laterally, the Lower Asmari has been charged vertically and laterally.

Petrological and organic geochemical characteristics of oil sands from the Middle Jurassic Yan’an Formation in the southern Ordos Basin, China

An integrated petrological and geochemical analysis of surface and drilled oil sands from the Middle Jurassic Yan’an Formation in the southern Ordos Basin was conducted to investigate the petrophysical properties, organic matter origin/type, and thermal maturity and their relation to environmental conditions during sediment deposition. Petrographic analysis (thin section, scanning electron microscopy (SEM), and porosity and permeability determination) of the oil sand was performed to establish the relationships between porosity and permeability and bulk density, reservoir quality index (RQI), normalized porosity index (NPI), and flow zone indicator (FZI). Geochemical analyses include oil extraction, column chromatography, and gas chromatography–mass spectrometry (GC-MS). The strong correlation between RQI and permeability (R2 = 0.98) reveals that porosity has a good correlation with RQI. The positive correlations between porosity and permeability and NPI and RQI (R2 = 0.77 and R2 = 0.65, respectively) show that the studied rocks contain many large pores with pore-to-pore throat connection structures that enhance permeability, which is further supported by the relatively high connection coefficient between NPI and RQI (R2 = 0.65). The organic matter in the Yan’an Formation is mainly composed of oil-prone type I kerogen indicated by the recovery of a large amount of crude oil rich in saturated hydrocarbon fractions from the extracted oil. The biomarker signatures of the analyzed oil (nC13-nC35, Pr/n-C17 and Ph/n-C18, and low C27/C29 regular sterane) reveal predominantly land plant materials as organic input sources based on the average concentration of αααC27:C28:C29 sterane 20R of approximately 38%, 22%, and 40%, respectively, and on high values of tricyclic terpane/αβC30 hopane and regular sterane/αβC30 hopane. Deposition within a lacustrine paleoenvironment under anoxic conditions enhanced organic matter preservation in the area based on the low Pr/Ph ratios (average 0.74), low αβC31-22R-hopane/αβC30 hopane ratios, and high C26/C25 tricyclic terpane ratios, as well as the presence of gammacerane and low water salinity. Biomarker maturity parameters (e.g., C32 homohopane 22S/(22S + 22R), moretane/hopane, and C29 sterane 20S/(20S + 20R) ratios and CPI) show that the extracted oil sand entered the early oil window stage.

Geochemical characteristics of the organic matter in UPPMRs and the implication for fluid–rock exchange due to the retrograde metamorphism in the Dabie–Sulu orogenic belt, North China

The samples were collected from ultrahigh-pressure para-metamorphic rocks (UPPMRs) around 500–2000 m deep by Chinese Continental Scientific Drilling. The combined method of ultrasonic disintegrator and Soxhlet was strictly conducted to extract the indigenous hydrocarbons from the UPPMRs, to obtain non-contaminated and entire organic matter to reveal the geochemical characteristics and origin of hydrocarbons in the UPPMRs. Through gas chromatography–mass spectrometry analysis, the ratios of Pr/Ph in the soluble hydrocarbon were from 0.04 to 0.87. It was inferred that the precursor of extracts would be deposited in the anoxic setting. Based on the relative content among C27, C28 and C29 steranes, it was found that the main source of organic matter was marine algae. But the isomer ratios of C31 hopane 22S/(22S + 22R) were 0.39–0.69, and the distribution range of C29 sterane 20S/(20S + 20R) was 0.41–0.63, both of which reflected the equivalent maturity of organic matter was no more than 1% (Ro%). Therefore, the immature organic matter derived from algae obviously conflicted with its host rock, which experienced ultrahigh-pressure metamorphism. Therefore, this sort of immature organic matter probably is of secondary origin. Furthermore, the chromatography of n-alkane almost assumes bimodal distribution, and the data of Tmax ranges from 394 to 565°C, as S1/total organic carbon (TOC) ratios systematically increase with the corresponding Tmax. Therefore, it could be further proved that the organic matter in the UPPMRs probably is of mixed origin and is mainly derived from immigrant hydrocarbons during the stages of subduction and retrograde metamorphism. The emergence of Zr-in-rutile also indicates that the geological temperature was lower than that during the peak of metamorphism. Therefore, it could be inferred that the kerogen associated with rutile might go through diagenesis regularly at the stage of retrograde metamorphism. It was also shown that the δ18O value suddenly reduced up to −10‰ corresponding to the highest TOC (1820 μg/g) around the subduction fault. The relationship between the TOC and δ18O value indicated that the fluid–rock exchange reaction was the main reason for the immature organic matter present in the para-metamorphic rock. The returned subduction and retrograde metamorphism resulted in the activity of the formation fluid, which could prominently impact the geochemical characteristics of the para-metamorphic rock and should also be considered in the geodynamics research of the metamorphic orogenic belt.

Origin of organic matter and hydrocarbon potential of Permian Gondwana coaly shales intercalated in coals/sands of the Barapukuria basin, Bangladesh

This paper presents the characteristics of source organic matter (OM), hydrocarbon potential (HC) and the depositional system of Gondwana coaly shales in the Carboniferous-Permian succession in drill hole GDH-40, Barapukuria basin, Bangladesh. Twelve layers intercalated in coals and sands were examined using Hydrogen Index (HI) of Rock Eval analysis, biomarkers in saturated HC fractions, polycyclic aromatic hydrocarbons (PAHs), and stable carbon (δ13Corg) and nitrogen (δ15Ntot) isotope ratios. The coaly shales showed a wide range of total organic carbon (TOC) content (2.3–30.3 wt%), intermediate to high TOC/TN ratios (14–39) and low total sulfur (TS) contents (<0.3 wt%), suggesting deposition in a freshwater environment occasionally influenced by brackish water. OMs with low to moderate HI (20–204 mg HC/g TOC) were deposited in a shallow terrestrial basin. The HC potentials are high in the middle and lower parts of the succession, with increasing TOC content dominated by terrestrial plants. The higher total HC generation potential up to 60.1 mg HC/g is attributed to coaction of high TOC and HI values. The HI values show good positive correlations with Pr/Ph ratios (r = 0.90), n-C>25/n-Ctotal alkanes (r = 0.86), phenanthrene (r = 0.75), methylphenanthrene (MP, r = 0.75), Tm/Ts (r = 0.74), sterane C29/C(27+28+29) (r = 0.69), Pr/n-C17 ratio (r = 0.69) and TS (r = 0.68). The coaly shales also contain abundant retene. Higher δ15N ratios coupled with high HI values suggest that the climate had a dry season. Very small amounts of oleanane and low ratios of oleanane/C30-hopane show negative correlations with HI values (r = −0.68). A significant input of algae and/or planktonic organisms occurred in the upper part of the core, estimated based on regular sterane compositions, but this did not increase the HI values. Relatively abundant hopanes (steranes/hopanes = 0.11–0.40) implied greater contribution of methanogen in the upper part of the succession and increased activity of aerobic bacteria in the middle to lower parts, respectively. Organic maturity is considered to be in the early to medium stage of oil generation, according to C29 sterane 20S/(20S + 20R) ratios of 0.28–0.49. Based on these results, most OMs originated from ferns, pteridospermic gymnosperms, peat mosses and/or submerged/floating plants, occasionally supplemented by a specific gymnosperm OM with epicuticular wax. Potential of HC generation of these coaly shales probably increased with increasing deposition of liptinite materials. Fluoranthene (Fla), pyrene (Py), benzo[e]pyrene (BePy) and benzo[bjk]fluoranthene (Bflas) are abundant PAHs in the coaly shales, and the ratios of low Fla./Py, benzo[a]anthracene (BaAn)/228 and indeno[1,2,3-cd]pyrene/(indeno[1,2,3-cd]pyrene + benzo[ghi]perylene) (InPy/(InPy + BghiP)) suggest that these 4- to 6-ring PAHs were mainly formed by small- to medium-scale wildfires during the dry season.

Organic geochemistry of the Middle-Upper Jurassic Naokelekan Formation in the Ajil and Balad oil fields, northern Iraq

Sixteen organic-rich argillaceous limestone and black shale samples from three wells with up to 16 wt% TOC (average 9.32 wt%) from the Middle–Upper Jurassic Naokelekan Formation in the west Zagros Basin of northern Iraq were evaluated as source rocks. Both organic geochemical and molecular data indicate an open marine environment at the time of deposition, leading to accumulation of Type-II and Type-III kerogen with varying oil and gas generation potential. The predominance of short-chain n-alkanes (n-C13–n-C19), and C27 and C29 steranes, and absence of oleanane confirm the dominantly planktonic/bacterial and algal origin of the organic matter. Organic richness, low Pr/Ph, and high C35/C34 homohopane ratios suggest alternating anoxic to suboxic depositional conditions. Biomarker distributions are consistent with sporadic anoxia, with unequivocal evidence for stratification of the water column and hypersalinity. The 22S/(22S + 22R) ratios for C32 homohopanes, moretane/hopane, and C29 sterane 20S/(20S + 20R) and ββ/(ββ+αα) ratios vary irregularly, whereas the C27 diasteranes, Ts/(Tm + Ts), triaromatic cracking and MDR ratios vary substantially and increase with burial depth among different homologues within the same sample set, indicating the threshold to peak of the oil-generation window. Based on hierarchical cluster analysis (HCA) and principal component analysis (PCA) of 13 selected source-related biomarker ratios, the source rock extracts have been divided into three groups: Group-1 from the Ba-1 well, Balad oil field, and Groups-2 and -3 from the Aj-8 and Aj-12 wells, respectively, in the Ajil oil field.

Origin of petroleum accumulation in the Chaheji-gaojiapu structural belt of the Baxian Sag, Bohai Bay Basin, China: Insights from biomarker and geological analyses

Abstract The origin of petroleum accumulations in the Chaheji-gaojiapu structural belt of the Baxian Sag, Bohai Bay Basin was evaluated based on the results of Rock-Eval pyrolysis on 135 samples and a biomarker analysis on 26 source rock samples and 33 oil samples. The four possible source rock intervals have different biomarker assemblages and were deposited in different environments. For example, pristane/phytane, C27-diasterane/C27-sterane and C19/C23-tricyclic terpane ratios show an increasing trend, but (C28+C29)-tricyclic terpane/[(C28+C29)-tricyclic terpane + Ts] and steranes/hopanes parameters display a decreasing trend among the lower part of the first member (Es1L) and the middle (Es3M) and lower part (Es3L) of the third member of the Eocene Shahejie Formation. This finding indicates that a decreasing anoxic and alkaline environment with an increasing input of terrigenous organic matter developed during the deposition of the Es1L, Es3M and Es3L source rocks. However, the biomarker parameters of the forth member (Es4) of the Eocene Shahejie Formation display highly similar characteristics with the Es3L source rocks, except for the C29-sterane 20S/(20S + 20R) and C27-diasterane/C27-sterane ratios, which show obviously higher than the other source rock values. The Es3-derived oils are absolutely dominant in the Chaheji-gaojipu structural belt, based on the biomarker analysis of saturated hydrocarbon, with slight or no contributions from the Es1L and Es4 source rocks because of the low maturation for the Es1L source rock and the absence of vertical migrating channels for the Es4 source rock. Faults are vital to petroleum migration and accumulation in this area and demonstrate the following double effects: (1) the deep faults cutting off the Es3 source rocks are the key channels for oil vertical migration; (2) the shallow faults entrap oil and finally form the commercial oil pools. As a result, the fault block reservoir is the major oil-reservoir type in the Chaheji-gaojiapu structural zone, and the lithologic reservoir is another oil-reservoir type in this area. Based on 1D burial and thermal history modelling, the E3 and E4 source rocks reached the oil-generation peak at approximately 5 Ma and 20 Ma, respectively, but the Es1L source rock is still in the low-mature stage. Therefore, the process of the large oil migration and accumulation for the Es3 source rocks occurred during the late Neogene-Quaternary. Through this research, there are two considerable exploration potentials for this area, including condensate reservoirs in the deep strata and low-mature reservoirs in the Es1 stratum interval.

Features of liquid hydrocarbon and biomarker maturity ratios during HTHP semi-open system pyrolysis of type II and III source rocks

ABSTRACTIn order to study the liquid hydrocarbon generated by laboratory pyrolysis and the biomarker maturity ratios in expelled oil with the increasing simulation temperature, the Hydrous semi-open system high temperature high pressure (HTHP) pyrolysis experiments was performed on Type II and III source rocks from 350°C to 540°C. The results showed that expelled oil yields in both samples have a trend of increased first and then decreased with the increasing temperature, while an opposite tendency occurred in the residual oil. The biomarker maturity ratios, such as ∑C21−/∑C22+ ratio in n-alkanes, Pr/Ph ratio in isoprenoid alkenes, Ts/Tm in terpenes, and C29ββ/(αα + ββ) ratios in steranes are all better indicators in terms of maturity in pyrolysis. However, the maturity biomarkers ratios interpreted by the mechanism of isomerization such as C31-homohopanes 22S/(22S + 22R) and ααα C29-sterane 20S/(20S + 20R), which had already reached their equilibrium values, indicating that microbiological deterioration is one reason for the failure indicative function of αααC29sterane20S/(20S + 20R) ratio. This research may also play an important role in the studies about the evolution of sedimentary organic matters in geology.

The Geochemical Characteristics of Coals from the Junggar Basin in Northwest China and the Relation of the Configuration of Pristane with Maturity in Highly Mature and Over-Mature Samples

Coal samples analyzed from Junggar Basin are characterized by high Total Organic Carbon (TOC) contents (63.7-82.2%) in all samples, except the highly over-mature samples Ha-01 and Ha-02, and high S2 (60.5-83.0 mg HC/g rock) and Hydrogen Index (HI) values (77-118 mg HC/g TOC), indicating the coal rocks have excellent source rock potential. The Tmax values (418-531°C), C29 sterane 20S/(20S+20R) ratios (0.20-0.54) and C31 homohopane 22S/(22S+22R) ratios (0.26-0.61) indicate an immature to highly over-mature stage of organic matter, which is supported by the organic geochemical maturation parameters. In addition, n-alkane carbon numbers range from C11 to C33 with maxima at n-C19 or n-C23 , exhibiting unimodal distribution patterns except Ai-13 and Ha-01, and low Pr/Ph ratios (0.29-0.80) in Ai-01, Ai-13, Ha-01 and Ha-02, indicating a suboxic reductive environment. In Wu-8, Wei-09 and Shinan-20, the Pr/Ph ratios are clearly greater than 1.0 (2.43-3.23), indicating oxic depositional conditions.Furthermore, pristane isomers were identified in extracts from these coal samples. Using coals of different maturity, which correspond to vitrinite reflectances (%Ro ) of 0.36-2.99%, the Pristane Isomerization Ratio (PIR) (PIR = [6(R)10(R)+6(S)10(S)]/6(R)10(S)) ranges from 0.42 to 0.97 for the coal extracts. The value of the PIR, which is a molecular maturity parameter, is evaluated by analyzing a series of samples using known values of the molecular maturity parameter based on the sterane and hopane isomerization indices, and the Methyl Phenanthrene Index (MPI). Changes to the PIR in highly mature Ai-13 (Ro > 1.5%) and over-mature Ha-01 and Ha-02 (Ro > 2.0%) are clear; thus, a linear correlation is evident between the PIR and Ro . The results suggest that the PIR is an appropriate indicator of maturity for the highly mature and over-mature coal samples in the Junggar Basin.

Discovery of Carboniferous Oil Seepage in Qaidam Basin and Its Geological Significance

In this work, the oil seepage was found in calcite veins in Keluke formation of upper Carboniferous reservoirs. Based on the analysis of geochemical characteristics, the isomerization parameter of C29 sterane 20S/(20S + 20R) was obtained as 0.39 and Ts/Tm value as 1.12, indicating that the oil seepage was mature. The Pr/Ph value was 0.64 and the tricyclic terpane was characterized by high abundance of gamacerane, C27 > C29 sterane, and a normal distribution with C23 as the dominant peak. Moreover, the oil/oil and oil/source rock correlation of oil seepage and carboniferous source rock underground and surface indicated that the oil seepage was similar to crude in Mabei-2 well (1463 m) and Sin-3 well (1076 m) but was different from the other crude in north Qaidam basin. It is inferred that the oil seepage was authigenic crude in Carboniferous, and Carboniferous source rocks have contributed to the oils in Mabei-2 well (1463 m) and Sin-3 well (1076 m). This study offers new scientific evidence for the exploring of carboniferous in Qiandam basin.

Geochemical Evidence for Coal and Carbonaceous Mudstone as the Possible Major Oil Source Rock in the Jurassic Turpan Basin, Northwest China

AbstractPetroleum geologists have debated whether the hydrocarbons from Jurassic coal measures are derived from the coals, carbonaceous mudstones or coal‐measure mudstones in the Turpan Basin. Based on the geochemistry analysis of the 20 crude oils and 40 source rocks from the Turpan Basin, some data have been obtained as follows: carbon preference index and methylphenanthrene index of the Jurassic oils are 1.16–1.45 and 0.28–0.80, and the ααα C29 sterane 20S/(20S+20R) and C29 sterane ββ/(ββ+αα) are 0.44–0.51 and 0.4–0.54 respectively, which show the normal maturity of oils; the vitrinite reflectance of the source rocks from the Xishanyao to Badaowan Formations range from 0.47% to 0.97%, which indicate immature to mature thermal evolutionary stage and sufficient conditions for generating mass mature oil. The effect of hydrocarbon expulsion should be considered when studying the source of coal‐derived oil by using Biomarkers. Biomarkers in the Jurassic oils from the basin are similar to those in the coals and carbonaceous mudstones, with a strong predominant content of pristane, relatively high ratio of C15/C16 sesquiterpenoids (&gt;1), a relatively high content of low carbon number tricyclic terpanes and C24 tetracyclic terpane, little gammacerane and C29 Ts detected, an absolute predominant content of C29 sterane and a relatively high content of diasterane. However, the opposite characteristics are shown in mudstones, with an approximately equal content of pristane and phytane, relatively low ratio of C15/C16 sesquiterpenoids (&lt;1), a relatively high content of high carbon number tricyclic terpanes and a low content of C24 tetracyclic terpane, peaks of gammacerane and C29 Ts detected obviously and an increasing C27 sterane content All of these characteristics identify the coals and carbonaceous mudstones as the possible major oil source rocks in this area, and they were formed in the stronger oxidizing environment with shallower water than mudstones.

Problems with the application of heptane and isoheptane values as light hydrocarbon parameters

Abstract The light hydrocarbon data from 772 oil samples in 25 oilfields, together with GC/MS data from 338 saturated hydrocarbon samples were used to discuss the relationship between kerogen types, using the heptane value, isoheptane value and C29 sterane 20S/(S+R) ratio. Although the heptane and isoheptane values are related to kerogen type, the correlation is different from that in Thompson's interpretation, so the correlation cannot be directly used in research on land facies oils in China. Consideration should be taken when using the heptane and isoheptane values, as secondary alteration and mixed oil sources are the main factors leading to the abnormal change in heptane and isoheptane values. The heptane and isoheptane values have a larger maturity range than that of C29 sterane 20S/(S+R). There are three types of oil samples (original immature oil, altered oil and mixed source oil with different maturity) that may fall into the “Biodegradation” area of the Thompson interpretation. For the biodegraded oil in Thompson's interpretation, the reservoir may have undergone a secondary charge.

BIOMARKER GEOCHEMISTRY OF CRUDE OILS FROM THE QAIDAM BASIN, NW CHINA

A suite of 16 crude oil samples from 13 oilfields in the Qaidam Basin were analyzed using techniques including gas chromatography and gas chromatography ‐ mass spectrometry. Biomarker compositions and parameters were used to investigate the palaeoenvironmental and depositional conditions and to correlate the oils with eachother. Oils from the western Qaidam Basin have pristane/phytane (Pr/Ph) ratios of less than 0.7, and contain abundant gammacerane, C27 steranes, 4‐methyl steranes and long‐chain tricyclic terpanes. C29 sterane 20S/(20S+20R) and ββ/(ββ+αα) ratios show that the western Qaidam oils have variable maturities ranging from immature to mature. Oils from the northern Qaidam Basin, by contrast, have Pr/Ph ratios greater than 3, low gammacerane contents, and relatively abundant C29 steranes, bicyclic terpanes and alkylcyclohexanes. C29 sterane 20S/(20S+20R) and ββ/(ββ+αα) ratios indicate that the northern Qaidam oils are mature.δ13C values, which range from ‐25.4‰ to ‐28.3‰ with the exception of one oil from the north (‐3l.6‰), are similar for oils from both the northern and western parts of the Qaidam Basin. The oils'carbon isotope compositions are similar to those of the organic matter in potential source rocks.The western Qaidam oils are inferred to have originated from Tertiary source rocks deposited under anoxic and saline‐hypersaline lacustrine conditions with dominant algal organic matter. The northern Qaidam oils are interpreted to be derived from Jurassic source rocks which were deposited in a freshwater lacustrine environment and which are dominated by terrigenous organic matter.

Characteristics of aromatic hydrocarbons in crude oils

Crude oils from different basins in China, Australia and New Zealand were analyzed to character ize aromatic hydrocarbons produced in different environments by means of GC/MS. The distributions of some common compounds such as naphthalene, phenanthrene, ehrysene, pyrene, fluoranthene, fluorene, dibenzothiophene and dibenzofuran were found to be related to sedimentary environments. Especially the relative contents of fluorenes, dibenzofurans and dibenzothiophenes can be used to divide the oils into three types: (1) saline or marine carbonate environment; (2 ) fresh-brackish water lake; (3) swamp and coal-bearing sequence. Aromatic biomarkers (e.g. retene, nor-abietene, derivatives of lupeol and β-amyrin) represent higher plant inputs with respect to the precursors of crude oils. High contents of sulphur-containing compounds like benzothiophene and dibenzothiophene series indicate a reducing sulphur-abundant diagenetic condition. The benzohopane series (C32–C35) was identified both in hypersaline and coal-bearing basins, and it is postulated to be the result of strong bacteria activity. In all the samples, a complete series of alkyl benzenes was analyzed. The similarity of its carbon-number distribution with that of n-alkanes probably suggests their genetic relationship. The distribution of the methylphenanthrene series reflects the evolution degree of crude oils, MPI holding a positive correlation with C29-sterane 20S/(20S+20R).