Tricyclic Terpanes Research Articles

Geochemical characteristics and organic matter accumulation of argillaceous dolomite in a saline lacustrine basin: A case study from the paleogene xingouzui formation, Jianghan Basin, China

Shale oil resources have been discovered in argillaceous dolomite in the Lower Member of Paleogene Xingouzui Formation (LXF) of the Jianghan Basin, opening up a new field of shale oil exploration and development. Previous studies have mainly focused on the evaluation of reservoir quality, but the research on the enrichment mechanisms of organic matter (OM) in argillaceous dolomite is very limited or unknown. On the basis of organic geochemical and mineralogical data, combined with sedimentological analyses, the factors controlling the differential enrichment of OM in the LXF Member II oil Bed argillaceous dolomite are studied. The results show that the average TOC content of the samples is greater than 1.0%, which could be regarded as good source rocks. The kerogen type is mainly type II, with a small amount of type I and type III, and most of the samples are in the low-mature stage. Vertically, the development of the LXF Member II oil Bed argillaceous dolomite can be divided into three stages: the lower section (LS) has TOC content ranging from 0.57 to 4.95%, the middle section (MS) has a higher TOC content, between 0.55 and 9.52%, and the TOC content of the upper section (US) is relatively low, between 0.41 and 3.49%. The distribution of biomarkers showed that both higher plants and aquatic organisms contributed to the OM accumulation. The parameters of biomarkers such as pristane/phytane (Pr/Ph), gammacerane/C30 hopane (G/H), extended tricyclic terpane ratio (ETR) and their degree of dispersion, as well as sedimentological characteristics, indicate that the LS was deposited in a stratified deep waterbody with anoxic bottom water, the MS was deposited in a saline stratified moderate-deep waterbody with anoxic bottom water, and the US was deposited in a disturbed saline waterbody. Different sedimentary environments controlled the source of OM, the effectiveness of nutrients recycling and preservation conditions, which jointly affect the enrichment of OM. The stratified moderate-deep waterbody with anoxic bottom water and no physical disturbances, coupled with low terrigenous organic matter (TOM) inputs and the contribution of algae and other phytoplankton, are the best conditions for the enrichment of OM in argillaceous dolomite.

Possible explanations for the predominance of tricyclic terpanes over pentacyclic terpanes in oils and rock extracts

Hopanes and tricyclic terpanes were identified as the dominant terpanes in crude oils and source rock extracts many decades ago. The majority of terpane fingerprints consist of tricyclic terpanes ranging from C19 to C30 (higher members of the tricyclic terpanes are also present but typically not clearly evident due to the abundance of the hopanes) and hopanes ranging from C27 to C35. Within these two families of terpanes, variations will be observed resulting from factors such as source, depositional environments, maturity, biodegradation and migration. However, the most significant departure from a typical tricyclic and hopane type distribution is one entirely dominated by the tricyclic terpanes with the series extending to at least C40 and in many cases, beyond. There are a few reported occurrences of such distributions in the literature, but satisfactory explanations are limited and speculative.Characterization of numerous oils from Devonian-Mississippian age reservoirs in the STACK play in the Anadarko Basin, Oklahoma, has revealed that many of these oils have terpane fingerprints dominated by tricyclic terpanes with the virtual absence of hopanes. It is also of interest to note that there appear to be four additional series of tricyclic terpanes in many of these samples. While attempting to explain these distributions using previously published arguments, it appears there may be other factors at work leading to the dominance of the tricyclic terpanes in this region.This paper discusses previous explanations put forward to explain these somewhat unusual terpane distributions, followed by a brief discussion of the terpane distributions in the STACK oils. Similar distributions of tricyclic terpanes have also been observed in a number of Mississippian rocks in the region, suggesting a possible source for the tricyclic terpanes in these oils. Results from these rock extracts are integrated into the discussion related to the oils.In summary, it appears that maturity is probably the most significant driving force for these distributions, with preferential production of hopanes over the tricyclic terpanes at lower maturity levels. At the higher levels of maturity experienced by the unconventional reservoirs, only tricyclic precursors remain to generate oils dominated by the tricyclic terpanes. At the same time, potential source contributions cannot be ignored, as shown by the presence of extracts dominated by tricyclic terpanes in many of these core extracts.

Mixing scenario of a vagarious oil in the Dongying Depression, Bohai Bay Basin

An oil from the third Member of Shahejie Formation (Es3) in well C104 from the Dongying Depression, Bohai Bay Basin, exhibits a vagarious mixing scenario of considerably distinctive maturities. Detailed molecular geochemical analysis was performed on eight oil samples and ten source rock samples from the Paleogene Shahejie Formation and Mesozoic strata by gas chromatography–mass spectrometry analysis. Biomarkers such as terpanes, steranes and aromatic steroid hydrocarbons are abundantly preserved in the C104 oil, with the predominance of high-molecular-weight biomarkers for each class of components, such as pentacyclic terpanes and tricyclic terpanes, regular steranes and pregnanes, suggesting that the C104 oil is “immature”. However, the high values of maturity parameters derived from aromatic hydrocarbons consisting of MNR, DNR, TMNr, TNR1, TNR2, MPI-3 and MBPI indicate that the C104 oil has been highly mature. Hence, the C104 oil from the Es3 reservoir in the Dongying Depression witnessed multiple episodic charges of distinctive maturities and sources with highly mature source interfused into the immature fractions. Based on oil-oil and oil-source correlations, the “immature” fractions of the C104 oil are mainly from the source rocks of the Es4 Member in the Shahejie Formation, while the “highly mature” fractions of the C104 oil possess the possibility of Mesozoic sources. Potential highly mature source rocks in the Mesozoic strata probably remain undiscovered in the Dongying Depression, Bohai Bay Basin.

Geochemistry of the Cretaceous Chinkeh oil from Maxhamish field and Garbutt black shale in the Liard Basin, Canada: Implications for a liquid-rich shale hydrocarbon resource

The Cretaceous Garbutt Formation shale and crude oils from the Cretaceous Chinkeh Formation in Liard Basin were subjected to geochemical analysis including biomarker fingerprinting. The Chinkeh oils are sweet light oils with API gravity and geochemical markers typical for the late stage oil window maturity. The oils show good correlation to the Garbutt shale extracts for their sterane compositions, while there are some minor discrepancies amongst their terpane distributions. These differences include enhanced contribution of tricyclic terpanes, high C23 tricyclic terpanes versus C30 hopane and low C24 tetracyclic terpane versus C26 tricyclic terpanes for the Chinkeh oil compared with the Garbutt shale extracts. Although not analyzed during this study, the Triassic Toad/Grayling interval, as stratigraphic equivalents of the Montney and Doig formations in Western Canada Sedimentary Basin may account for the terpane compositional features. Therefore, it is likely that the Chinkeh oils are mainly sourced from the Cretaceous Garbutt shale with minor additional contributions from a Triassic source. The Garbutt Shale is immature in the Horn River Basin, while in the Liard Basin in a north to south transect the unit's thermal maturity ranges from early mature oil window to wet gas/condensate window, and thus may be prospective for unconventional liquid hydrocarbon resource recovery.

Investigation on the biodegradation levels of super heavy oils by parameter-striping method and refined Manco scale: a case study from the Chepaizi Uplift of Junggar Basin

The Carboniferous volcanic reservoir in the Chepaizi Uplift became an exploration hot target in recent years for its substantial amount of oils discovered. However, most of the Carboniferous heavy oils were biodegraded to PM7 or higher with orders of magnitude variation in oil viscosities. Two oil groups (I and II) exactly corresponding to the western and eastern Chepaizi Uplift were distinguished according to their source diagnose. Furthermore, three oil families (II1, II2 and II3), with the biodegradation level of PM7, PM8–8+, PM9+, respectively, were classified based on molecular compositions and parameter-stripping method of strongly bioresistant parameters. Allowing for this extremely high biodegradation case, more biodegradation refractory compound class were added to establish a refined Manco scale to quantitatively evaluate the biodegradation extent. Refined Manco number (RMN2) positively correlated with the oil density, NSO contents, and absolute concentrations of diasteranes and gammacerane, negatively correlated with the absolute concentrations of diahopane, summed tricyclic terpanes and pentacyclic terpanes. This refined scale showed higher resolution than the PM one to differentiate the biodegradation extent of Carboniferous heavy oils from the Chepaizi Uplift, especially those with same PM values but different oil viscosities.

Organic geochemical evaluation of Cretaceous Talhar Shale for shale oil and gas potential from Lower Indus Basin, Pakistan

A decline in conventional petroleum reserves has resulted in the study of unconventional reservoirs. Techniques, such as hydraulic fracturing, permit new types of reservoirs to be developed. Organically rich shales are the prime horizons for the exploration and development of unconventional oil/gas. The Talhar Shale is a unit of the Lower Goru Formation (Cretaceous), mainly composed of dark grey-black shale with minor siltstone and sandstone. In the study area, the Talhar Shale is 70–90 m thick. This research primarily focuses on the geochemical evaluation of the Talhar Shale to evaluate its shale oil and gas potential by using total organic carbon, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD), vitrinite reflectance, and maceral analysis. Talhar Shale has moderate to good hydrocarbon potential (0.43–10.73 mg HC/g rock). The laboratory results of the TOC reveals a good match with the Δlog R technique relative to the CARBOLOG technique. Biomarker data of the studied samples exhibit the dominance of C19 tricyclic terpanes, C30 pentacyclic triterpanes, and C27 steranes. Maturity parameters (Tmax, and vitrinite reflectance) suggest that the Talhar Shale is thermally peak-late mature, consistent with biomarker maturity parameters (steranes and hopanes). Oxic environmental conditions prevailed during the deposition of these Cretaceous sediments, and the organic matter was mainly mixed (primarily derived from terrigenous sources). This interpretation is based on various biomarker criteria, e.g., elevated Pr/Ph values, a large amount of C24TeT comparative to C23 TT, the lower amounts of C29/C30 17α(H)-hopane, etc. Organic petrographic analysis exhibits vitrinite as the dominant maceral group. However, solid bitumen, inertinite, and liptinite macerals were also observed. The van Krevelen diagram and the HI vs. Tmax indicate the presence of mixed type II/III kerogen. Various geochemical parameters, e.g., Tmax, n-alkanes carbon preference index (CPI), sterane parameters (20S/20S + 20R, ββ/ββ+αα), and the hopane Ts/(Ts + Tm) and C31 22S/(22S + 22R) suggest the orgaic matter (OM) in Talhar Shale is thermally mature. Based on XRD, the Cretaceous Talhar Shale contains a high percentage of quartz. Additionally, the crossplot between TOC and quartz content displays a positive association that suggests the quartz content in Talhar Shale might be from the biogenic origin, which supports a brittle nature and could be favorable for hydraulic fracturing. Moreover, it has a lower value of Poisson's ratio and moderates to high Young's modulus, indicating favourability for hydraulic fracking. Cretaceous sediments from the Lower Indus Basin of Pakistan are chiefly considered as oil and gas-prone horizons. Geochemical properties of the Talhar Shale compared with other major unconventional shale reservoirs around the globe (United States, Germany, Canada, and China) exhibits suitable average organic matter abundance (2.19 wt %), mixed type II/III kerogen, an adequate level of thermal maturity, massive shale thickness, burial depth, and high porosity. These characteristics of the Cretaceous Talhar Shale in the Lower Indus Basin compared to other global unconventional reservoirs may indicate its possibility as a favorable target for unconventional energy exploration.

Geochemistry of high-maturity crude oil and gas from deep reservoirs and their geological significance: A case study on Shuntuoguole low uplift, Tarim Basin, western China

The oils of Shuntuoguole low uplift of Tarim Basin in western China have high contents of saturated hydrocarbons and a high loss of light hydrocarbon components because of volatilization. These oils are characterized by low abundance of hopanes and high abundance of C28–30 tricyclic terpanes and dibenzothiophenes and relative high abundance of C20–23 terpanes, C21–22 5α-steranes, and diasteranes in the oils. Quantitative analysis of carbon isotope and biomarkers show that the oils in the Ordovician carbonate rocks are sourced by deep Cambrian and Ordovician marine shales and marls. Geochemistry of the oils indicates that the reservoir has undergone multistage accumulations, with the late-stage oils obscuring traces of biodegradation of paleo-oils charged in the early stage. The concentration of methyl adamantanes and steranes demonstrates that oils occurred in an early stage of intense oil-to-gas cracking. Most of the gases are wet, with dryness lower than 90%, and geochemical analysis suggests that they are mainly from thermal degradation of kerogen. This study suggests that in addition to oils sourced by deeper source rocks in the Shuntuoguole low uplift in situ, there are oils that migrated from the Manjiaer depression into the Shuntuoguole low uplift.

Origin and paleoenvironment of organic matter in the Wufeng–Longmaxi shales in the northeastern Sichuan basin

The formation environment and preservation conditions of sedimentary organic matter (OM) play an important role in the accumulation of shale gas. In the present study, inorganic and organic geochemical data were analyzed to determine the origin and preservation environment of sedimentary OM in the Wc-1 well of the Wufeng–Longmaxi (WF–LMX) Formation in northeastern Chongqing, China. In a biomarkers analysis, the numerical characteristics of n-alkanes ( n-C17/ n-C31>4.0), tricyclic terpenes (C23TT/C30H>1.0), and steranes (C27/C29St>1.0) suggested that the main origin of OM in the black shale was planktonic algae. High values of P/Ti and BaXS in the paleoproductivity indices suggested that primary productivity in the WF–LMX Formation was relatively high, peaking in the lower LMX Formation. Relative enrichment in U, V, and Mo, and the changing trends in V/(V+Ni) and Ni/Co suggested that the redox conditions for the bottom water, which changed from the WF Formation to the lower and upper LMX Formation, were oxic/dysoxic to anoxic and dysoxic, respectively. The relationship between total organic carbon and the above indexes indicates that different key factors controlled OM enrichment in the WF–LMX Formation. In the WF Formation, oxic bottom water was not conducive to the preservation of sedimentary OM. In the lower LMX Formation, the highest paleoproductivity and anoxic bottom water conditions promoted the enrichment and preservation of sedimentary OM. In the upper LMX Formation, excessive terrigenous inputs and relatively low paleoproductivity limited the enrichment of sedimentary OM.

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.

Hydrocarbon generation from bacterial biomass in ca. 1320 million years ago

Bacteria are the oldest life on the Earth. Some of them, such as cyanobacteria, can produce oxygen and organic matter through photosynthesis. However, the hydrocarbon generation ability of these bacterial biomass is still unclear. Here we reported the molecular evidence from the wrapped bitumen in well-preserved silicified concretions from the Xiamaling Formation, North China. The absence of steranes indicated negligible contribution of eukaryotic algae to the bitumen. Abundant hopanes, 13α(n-alkyl)-tricyclic terpanes and other biomarkers of bacteria prove that bacterial biogenic organic matter can generate hydrocarbons on a large scale. Combined with our previous microfossils and elements studies, these bitumen were considered to be from the Xiamaling shales, for the intrusion of Yanliao large igneous provinces into the organic-rich Xiamaling shales at ca. 1320 million years ago.

Geochemical characteristics and significance of the bitumen in Sinian reservoirs in Sichuan basin and its periphery

The bitumen of Doushantuo Formation distributed along fractures has been firstly discovered in the dolomite reservoirs of Dou-3 Member in Zigui region, Yichang, Hubei. Research has been conducted using multiple methods on the characteristics of the newly discovered bitumen of Doushantuo Formation, bitumen of Dengying Formation-Longwangmiao Formation in Anyue gas field in Sichuan Basin, and bitumen of Sinian and source rocks of Sinian-Cambrian in Northeast Sichuan. The results show:①The reflectivity of the bitumen of Dou-3 Member is about 2.8%; ② The carbon number of n-alkanes in the bitumen of Dou-3 Member is C13-C33, where nC17 is the main peak; the relative proportion of the regular steranes is C27≈C29>C28, and C27, C28 and C29ααα20R steranes are distributed in “L” shape; abundant tricyclic terpanes and pentacyclic triterpanes have been detected, and the abundance of gammacerane is high; Aromatics are mainly phenanthrene series compounds. ③ The heteroatomic compounds in the bitumen of Dou-3 Member are mainly O2 carboxylic acids, and the oxygen compounds in the bitumen of Dengying Formation in Anyue gas field are close to those of the source rocks of Doushantuo Formation. The research results are of vital guiding significance to the study of potential source rocks of Doushantuo Formation in Sichuan Basin and the exploration of oil and gas from the source rocks of Doushantuo Formation.

Organic geochemical characteristics and comparison of the source rocks and the severely biodegradable oil sands around Karamay, China

For the sake of explaining the organic geochemical characteristics of the hydrocarbon source rocks (SRs) around Karamay, such as thermal maturity (TM) (evidences from the temperature of maximum pyrolysis yield (Tmax), the Carbon Preference Index (CPI) and Odd to Even Preference (OEP) values, the C30 M/H versus Tm/Ts, the C29 ββ/(ββ + αα) versus C29 20 S/(20 S + 20 R)), hydrocarbon potential (HP) (evidences from total organic carbon (TOC) and rock pyrolysis (RP)), organic matter (OM) source input (evidences from n-Alkane distribution, the relative quantity of C27-C28-C29 steranes, the (C19 + C20)/C23 tricyclic terpane (TT), and the Terrigenous/aquatic ratio (TAR)) as well as paleoenvironment (evidences from the pristane/phytane (Pr/Ph) and the Gammacerane index), and in order to analyze the biodegradation degree and source of oil sand (OS) oil, 55 core samples of SRs in all were selected to measure TOC and RP. 14 core samples of SRs and 3 OS samples were selected for gas chromatography–mass spectrometry (GC-MS) analysis. 11 core samples of SRs and 3 OS samples were used for organic carbon isotope (OCI) analysis. The results indicate that except the SR from Fengcheng formation (P1 f) which is in the stage of high or over evolution, the other SRs are in mature stage. OM type of Carboniferous (C) SRs are type Ⅱ kerogen, with the largest abundance. OM type of the SRs in Wuerhe formation (P2 w) and Jiamuhe formation (P1 j) are type Ⅲ kerogen with good and medium OM abundances. Almost all SRs were formed in the reduction environment of high salinity, and the main OM source input is the lower aquatic plants. Karamay formation (T2 k) and Badaowan formation (J1 b) oil sands (OSs) around Karamay have undergone serious biodegradation. It is suggested that OS oil are mainly from P1 f SRs (evidences from the tricyclic terpanes (TT), triarysteranes, pregnane, homopregnane and OCI).

Oil origins, mixing and biodegradation in southwestern Junggar Basin, NW China

The southwestern Junggar Basin is an attractive region for oil exploration. A major discovery of high oil production rate from a recently drilled borehole stimulated a new round of extensive petroleum exploration in this region. The potential source beds are within the Permian, Triassic, Jurassic, Cretaceous and Paleogene strata, but no effective oil-prone source rock samples have been drilled so far due to deep burial, leading to that oil source correlation remains controversial in the region. A total of 38 crude oils and the free, adsorbed and inclusion oils obtained from 18 oil-containing reservoir rocks from the southwestern and southern Junggar Basin were analyzed by GC, GC–MS and GC–IRMS for the purpose to classify oil groups, determine oil origins, and identify effective source beds in sags. Crude oils in the southwestern Junggar Basin can be classified into two end groups and an intermediate group, namely PO, JO and PJO oils, which were originated from the Permian lacustrine source beds, Jurassic terrigenous source beds and both, respectively. Ratios of C19/C20 tricyclic terpanes and C24 tetracyclic/(C24 tetracyclic + C26 tricyclic) terpanes are the most sensitive parameters to distinguish these three groups of oils. These two ratios increase from PO, PJO to JO oils. JO oils can be further classified into two subgroups, i.e. J1O and J2O. J2O oils have substantially higher amounts of C27 and C28 steranes relative to C29 steranes, higher amount of gammacerane, lower amount of C29 diasteranes, and lower isomerization ratios of steranes, compared with J1O oils. J1O oils were exclusively originated from the Jurassic source beds while J2O oil were mainly originated from the Jurassic source beds mixed with minor oils generated from the Paleogene and Cretaceous lacustrine source beds. In the Chepaizi uplift, the major PO oils and extracted oils from 14 reservoir rocks were mainly originated from source beds within the Lower Wuerhe Formation of Middle Permian (P2w). However, the remaining minor oil samples and extracted oils from the other four reservoir rocks were clearly originated from source beds in the Fengcheng Formation of Lower Permian (P1f) on the basis of molecular parameters and δ13C values of individual n-alkanes, indicating the presence of effective oil-prone source beds within the Fengcheng Formation in the Shawan sag. In shallow reservoirs within the Neogene Shawan Formation (N1s), PO, PJO and J1O oils are severely biodegraded while J2O oils have nearly no biodegradation effect because the former entered the reservoirs much earlier than the latter.

Geochemically Distinct Oil Families in the Gudong Oilfield, Zhanhua Depression, Bohai Bay Basin, China.

Twenty crude oil samples were obtained from the Gudong Oilfield and their organic geochemical characteristics were analyzed. The oil samples were classified into three families by hierarchical cluster analysis and principal component analysis based on 13 source-related and depositional environment-related biomarker parameters. Oils in family I have low ratios of C19/C23 tricyclic terpanes and C24 tetracyclic terpane/C26 tricyclic terpanes, and relatively high ratios of steranes/hopanes and C30 4-methylsteranes/ααα20R C29 sterane, thus indicating that microalgae were the dominant organic matter input for the source rocks of family I. The gammacerane/C30 hopane ratios are higher than that of family II and family III, whereas the C35/C34 homohopane ratios are lower, thus indicating a suboxic, brackish water environment for the source rocks. The inferred source rock is the first member of the Shahejie Formation in the Huanghekou Sag. Family II is characterized by high ratios of C19/C23 tricyclic terpanes and C24 tetracyclic terpane/C26 tricyclic terpanes but relatively low ratios of steranes/hopanes and C27/C29 αααR steranes. These findings suggest that the original organic matter of the source rocks had a greater contribution from terrigenous higher plants than from microalgal. The relatively low ratios of gammacerane/C30 hopane and C35/C34 homohopane suggest that the source rocks were deposited in an oxic environment with a low salinity, thus corresponding to the Dongying Formation in the Huanghekou Sag. Family III oils have high C27/C29 ααααR steranes ratios and low C30 4-methylsteranes/ααα20R C29 ratios, which indicate the contribution of microalgae (especially zooplankton algae) to the source rocks. The relatively high abundance of C35 homohopane and low gammacerane/C30 hopane ratios suggest a weakly reducing condition with low salinity, which is in accordance with the third member of the Shahejie Formation in the Gunan Sag. The C31S/(S + R) homohopane ratios imply that oil samples in this study are in the mature stage, although the ratios of C2920S/(20S + 20R) and C29ββ/(αα + ββ) steranes suggest that the maturity of family II is higher than that of family I and family III.

Organic geochemical compositions of Mesoproterozoic source rocks in the Yanliao Rift, Northern China

Organic-rich Mesoproterozoic rocks from the Xiamaling and Hongshuizhuang formations, with a moderate thermal maturity within the oil window, are well preserved in the Yanliao Rift, Northern China. Their organic geochemical compositions, especially biomarkers, organic matter origin, and depositional environment, are discussed in detail using GC, GC–MS and GC-MS-MS techniques. The results indicate that the Xiamaling and Hongshuizhuang samples share similar molecular compositions, which are distinct from those of Phanerozoic bitumens, suggesting a unique microflora in the North China sea during the Middle Mesoproterozoic (1.45–1.30 Gyr). The biomarkers in the saturated fraction were dominated by 13α(n-alkyl)-tricyclic terpanes (13αNATTs) and drimanes. The 13αNATTs appeared to be diagnostic biomarkers for special, ancient microbes in the Proterozoic, as they were only detected in Meso–Neoproterozoic bitumens and were absent in Phanerozoic sequences. Abundant drimane series, including extended drimanes, may be sourced from the ring C cleavage of 13αNATTs or may directly originate from the same precursor of 13αNATTs, based on the observation that the concentrations of drimanes and 13αNATTs exhibited a good correlation. Elevated C19 and C20 regular tricyclic terpanes together with abundant rearranged hopanes, which are usually typical fingerprints for terrestrial rocks, are distinct features of the Xiamaling and Hongshuizhuang marine rock samples. These compounds are considered to be derived from unique prokaryotes that were present in the Mesoproterozoic sea, which could synthesize abundant precursors of rearranged hopanes and low molecular tricyclic terpanes. Pristane (Pr) and phytane (Ph), mainly originated from the phytol side-chain of chlorophyll, were only present in very low abundances, even in the low maturity and organic-rich Xiamaling oil shales (total organic carbon >20%). This may indicate a contribution of phototrophs with other molecular proxies, rather than phytanic lipids in their chlorophylls. An absence or trace amounts of steranes in the samples may reveal a low contribution of eukaryotes, although previous studies have found a wide occurrence of eukaryotes in the Xiamaling and Hongshuizhuang formations, as well as in even more ancient rocks in the Yanliao Rift. Low Pr/Ph ratio values (<1.0), together with an absence of dibenzothiophenes and aryl isoprenoids, may indicate a common anoxic environment with relatively low sulfate concentrations and a low contribution of green sulfur bacteria. Several maturity indictors, such as Tmax, C31 22 S/(22 S + 22 R), and the methylphenanthrene index, all suggest an early oil-window thermal maturity for the Xiamaling rocks and a middle oil-window maturity for the Hongshuizhuang rocks.

Deposition characteristics of pliocene coals in the denizli region (SW Turkey) via organic petrography, geochemistry, and stable isotope composition

The objective of this study is to identify and evaluate the organic geochemical properties, paleo vegetation, and paleo depositional environment of coals in Denizli (SW Turkey). Organic geochemical and petrographic investigations, scanning electron microscopy, X-ray diffractometry, and palynological and stable isotope (δ2H, δ13C, δ15N, δ18O and δ34S) investigations have been performed. Coal, clayey coal, and coaly claystone samples from the study area have gas and oil production potential according to their total organic carbon (0.59–48.30 wt%), hydrogen index (56–286 mg HC/g TOC), oxygen index (30–121 mg CO2/g TOC) and S2/S3 (0.47–9.59) values. Dominant maceral assemblages included huminites and low amounts of liptinite group macerals. Tissue preservation index (0.39–5.13), gelification index (4.11–96.83), groundwater index (0.40–8.77) and vegetation index (0.49–42.67) parameters indicate a limno-telmatic environment and increased woody tissue. Mean random huminite/vitrinite reflectance values (ranging from 0.23 to 0.41 %Ro) denote lignite and sub-bituminous C and B ranked coals. Carpinus, Alnus, Zelkova, Platanus-Salix, Carya, and Ostrya were found through palynologic investigations. In addition, freshwater algae Botryococcus was detected in coal samples from Denizli. δ13C, δ15N values and C/N ratios indicated a terrestrial C3 ecosystem. Some sterane and tricyclic terpane ratios and aromatic biomarkers have shown that high plant input, immature organic matter and oxic-suboxic conditions are predominant in the depositional environment.

Molecular marker and carbon isotope geochemistry of ordovician oils in the Tuofutai Bulge, northern Tarim Basin: Implications for oil maturity, source characteristics and filling directions

The Tuofutai Bulge in the Tabei Uplift of Tarim Basin, western China, has become a hot spot for petroleum exploration in recent years. Fifteen Ordovician oil samples from 15 wells in the Tuofutai Bulge were analyzed for biomarkers and carbon isotopes using gas chromatography–mass spectrometry and stable carbon isotope analysis to constrain its depositional environment, thermal maturity, source rocks and the possible petroleum charging directions. The samples were characterized by abundant terpenoids, relatively high contents of C29 regular steranes and dibenzothiophene, relatively low ratios for Pr/Ph and C22/C21 tricyclic terpanes, and high ratios of C35/C34 homohopanes. Results suggest that the source rocks for the oils were deposited in a reducing marine carbonate and marl environment. Cambrian and Ordovician source rocks contribute to the oils, and the Middle to Upper Ordovician source rocks exert a greater contribution. n-alkanes and abundant 25-norhopanes in the saturated fractions suggest that the oil is a mixture of early biodegraded oil and late normal crude oil charged at later time. Data from methyldiamantane parameters suggest that the crude oil is in a high maturity stage. The tracing of oil charging suggests that preferential migration directions are primarily from south to north, connected with oil migration along the Shenbei No.1 Fault from the Shuntuoguole Lower Uplift to the south of Tabei Uplift.

Degradation-resistant biomarkers in the Pirambóia Formation tar sands (Triassic) and their correlation with organic facies of the Irati Formation source rocks (Permian), Paraná Basin (Brazil)

The Pirambóia Formation tar sands constitute one remarkable occurrence of heavy oil in the eastern border of the Paraná Basin, São Paulo State, Brazil, being characterized as highly degraded oils related to the Irati-Pirambóia oil system. In this context, the aim of the present work was to investigate biomarkers that are more resistant to degradation and use them to establish a more reliable geochemical correlation between the tar sand oils of the Pirambóia Formation (collected from the Fazenda Betumita and Guareí I outcrops) and the organic extracts of black shales of the Irati Formation (facies Irati A and B, collected in the Amaral Machado Quarry, São Paulo State). For this purpose, analysis of stable carbon isotopes and diagnostic ratios of saturated and aromatic biomarkers were investigated, and the most reliable diagnostic ratios were selected based on the principal component statistical analysis. The results pointed to different degradation extent between the tar sand outcrops, being higher for the Guareí I samples. In this scenario, it was verified that most of the diagnostic ratios commonly used in oil-source rock correlation studies were susceptible to degradation processes. It was also observed that samples from Pirambóia and Irati formations are at the beginning of the oil generation window, with the C29 ββ/(αα + ββ) ratio as the most suitable to assess thermal maturity of extremely degraded oils. The multivariate statistical analysis of the results, based on ten more resistant diagnostic ratios, allowed to select six main variables responsible for the similarity between the samples from the Irati and Pirambóia formations: δ13C (‰), TPP ratio (C30 tetracyclic polyprenoids over diasteranes), %C28 and %C29 monoaromatic steranes, (C20 + C21)/(C23 + C24) tricyclic terpanes, and C23 tricyclic terpane/(C23 tricyclic terpane + C29 hopane). These geochemical parameters showed greater reliability in the correlation between the Pirambóia Formation tar sand oils and the Irati samples of the facies A, deposited in a restricted marine environment under anoxic-euxinic conditions.

Significance to hydrocarbon exploration of terrestrial organic matter introduced into deep marine systems: Insights from the Lower Cretaceous in the Levant Basin

Oil shows from wells in the Levant Basin and Egypt are suggestive of potential economic discoveries within unpenetrated Mesozoic reservoirs in the Eastern Mediterranean. Analysis of some of these oils indicate a non-marine source of mixed deltaic-terrestrial or lacustrine origin for the organic matter. Data from Barremian-Aptian sediments from the MNUPH-1 core in northern Israel opens a window on potential importance of terrestrial-sourced kerogen deposited in source rocks in a marine depositional environment.Core analyses of the Barremian Nabi Sa'id Fm. demonstrate the occurrence of a gas-prone immature source rock of >77 m gross thickness averaging 4.6% TOC, peaking at 37% TOC. Rock-Eval pyrolysis, biomarker n-alkane, sterane, and tricyclic terpane indices, atomic C/N ratios, and δ13Corg ranges indicate mixed terrestrial-marine organic source rocks for the Barremian, while higher up, the Aptian Hidra Fm. contains source rocks with organic matter derived dominantly from carbohydrate-rich land plants. The interval at MNUPH-1 includes abundant evidence for off-shelf mass transport of terrestrial and proximal marine sediments into the deep marine basin. These features are used to explain the anomaly of a terrestrial source for organic matter in this setting. Mass transport and consequent mixing of distal marine, proximal marine and land-derived sediment is, in fact, the norm at the foot of continental slopes globally.The dominantly type III source rocks described here would be unlikely to expel oil but might produce thermogenic gas. Thermogenic gas identified in similar marine settings might wrongly be interpreted as having been generated from marine organic matter, misleadingly indicative of a prospective oil source. When prospecting for deep-rooted hydrocarbon accumulations in offshore marine settings, an alternative system dominated by basinward sediment transport of gas-prone ‘terrestrial’ source rocks into strategically-positioned toe-of-slope marine settings, is supported here, and could well be producing gas in the Levant Basin.

Geochemical characterization and origin of crude oils in the Oriente basin, Ecuador, South America

The Cretaceous oil reservoir located in eastern slope belt of the Oriente basin accounts for most of the discoveries in last decade in Ecuador, which makes the Oriente basin one of the most important oil exploration targets in South America. Crude oil samples (n = 31) in 31 wells together with mudstone and limestone source rocks (n = 18) from Cretaceous Napo Formation in 16 wells were analyzed to evaluate the geochemical characteristics of the oil reservoir oil.Geochemical analyses included measurements of total organic carbon (TOC) content, Rock-Eval Pyrolysis, gas chromatography (GC), and gas chromatography-mass-spectrometry (GC-MS).All the oil samples have pre-uimodal n-alkane distribution dominated by lower molecular weight components (peak at C15–C17) with a small peak at C25–C30. The carbon preference index (CPI) and odd-over-even predominance (OEP) values range between 1.0 and 1.34, and 1.0–1.21 respectively; Pr/Ph ratios range from 0.67 to 1.16; high Pr/n-C17 (0.80–3.47) and Ph/n-C18 ratios (0.82–7.86) values and dominate C27 regular steranes, all these biomarkers show that the oil derived from marine algal material. Furthermore, all oils have similar Terpanes and Steranes distribution shape, peak at C23TT, and low at C22TT (TT = tricyclic terpanes), relative low C22/C21, C24/C23 and C26/C25 tricyclic terpane ratios, higher C27R (R = regular steranes) content than C29R and C28R. These biomarkers demonstrate that all the oils are from same genetic family although they came from different zones. There are two kinds of source rocks in the Oriente basin, shale and argillaceous bioclastic limestone of Napo Formation. These rocks are good-excellent mature according to TOC and Rock-Eval assessment. The two source rocks show obvious different Terpanes and Steranes distribution shape in mz191 and mz217 maps. The Oil-Source correlation analysis demonstrates that the crude oils have similar Terpane and Steranes distribution shape and biomarker value, especially the C27R–C28R–C29R ratio, with argillaceous bioclastic limestone of Napo Formation. This new geochemical data suggests that the argillaceous bioclastic limestone is the major source rock in the Oriente basin. Thus, distribution of this stratigraphic unit should be the key point for future exploration.