Terpane Distributions Research Articles

Petroleum Potential and Organic-Matter–Oil Correlation in the Rocks of the Upper Riphean Iremeken Formation in the Kamo Arch of the Baikit Anteclise (Siberian Platform)

Abstract —A complex of laboratory studies of Riphean rocks and oils was carried out by the organic-geochemistry methods to construct a basin model for the Kamo arch of the Baikit anteclise of the Siberian craton. We compared the parameters of the organic matter (OM) and oils of the Upper Riphean Iremeken carbonaceous member by biomarker hydrocarbons. Analysis of the obtained chromatography–mass spectrometry data showed an unordinary group hydrocarbon composition of extracts from the OM and oils and low contents of cheilanthanes and steranes in them. Within the Kamo arch, the Upper Riphean Iremeken OM-enriched deposits with a high petroleum potential might have reached the peak of petroleum generation only in the deepest part of the Madra trough; thus, the traps could not be completely filled with oil. The distribution of tricyclic terpanes in the rock bitumens from the studied wells testifies to immature OM in the Iremeken Formation. However, in the most submerged zones of the Kamo arch and in the adjacent areas, oil was generated from the OM of the Iremeken Formation. This is evidenced by the oils of the Upper Iremeken Subformation in the Kuyumbinskoe field and the Ter’-Kamo license area.

The La Luna Formation, Venezuela: A prospective unconventional reservoir

Since the early 2000s, the exploitation of unconventional reservoirs has become very important to the oil and gas industry because of their high potential source of energy and economic value. Venezuela possesses a world-class hydrocarbon source rock in one of the most prolific hydrocarbon basins in the world, namely the Cretaceous La Luna Formation in the Maracaibo Basin. Outcrop and core samples collected from the northwestern Maracaibo Basin provide the database for this study. A comprehensive multiscale characterization of the samples is undertaken to unravel the stratigraphic properties of the petroleum system. In addition, a geochemical approach is taken to evaluate the prospectivity of the La Luna Formation as an unconventional resource in the Maracaibo Basin. Rock-Eval pyrolysis and biomarker data indicate that the La Luna Formation is dominated by type II kerogen, indicating an oil-prone marine organic matter origin. Total organic carbon values range between 3.85 wt% and 9.10 wt%. Distributions of isoprenoids, steranes, and terpanes including gammacerane and monoaromatic steroid hydrocarbons indicate a hypersaline, marine carbonate anoxic depositional environment. Thermal maturity parameters indicate that most of the cores are currently in the oil window. This combined stratigraphic geochemical study indicates that the La Luna Formation has excellent potential as an unconventional reservoir for oil and gas in the study area.

The enhanced presence of tricyclic terpanes in the lacustrine rock extracts of the Upper Triassic Yanchang Formation, Qingcheng area, Ordos Basin, China

The predominance of tricyclic terpanes over hopanes was observed for the first time in the lacustrine rock extracts of the Upper Yanchang Formation collected from Well CYX in the Qingcheng area, Ordos Basin, China. Specifically, hopanes are dominant terpanes in the Chang 7-2 member, while tricyclic terpanes ranging from C19 to C39 predominate over hopanes in the Chang 7–3 and Upper Chang 8-1 member. The distributions of terpanes, steranes, as well as n-alkanes vary significantly in these thermally mature rock extracts, however, are closely correlated in each sample. Generally, rock extracts comprising more abundant tricyclic terpanes and their lower molecular weight homologues are characterized by having lower Pr/n-C17 ratios and by containing more abundant low molecular weight n-alkanes (n-C21-) and short-chain C21-22 steranes. Furthermore, among the Chang 7–2 and Chang 7-3 samples, black shales contain more abundant low molecular weight tricyclic terpanes and n-alkanes (n-C21-), and short-chain C21-22 steranes when compared with siltstones and mudstones, which comprise more abundant hopanes, diasteranes and regular C27-29 steranes. The similar geochemical characteristics could also be found in other rock extracts that have variable abundances of tricyclic terpanes and hopanes, especially in the East Berlin Formation (Hartford Basin, Connecticut, U.S.A), which suggests that the causes for the variable distributions of terpanes, steranes and n-alkanes in these strata are similar.On the one hand, it is determined by the proportion of aquatic versus terrigenous source input and depositional environment. The predominance of tricyclic terpanes over hopanes and short-chain C21-22 steranes over regular C27-29 steranes in the Chang 7-3 member, especially in black shales, could be resulted from algal bloom and possibly associated microbial metabolic process in stable or stratified water column, which may be triggered by plentiful nutrients provided by runoff, volcanic or hydrothermal events. On the other hand, high hydrocarbon-generation intensity and petroleum expulsion efficiency for source rocks, especially for black shales, may be another significant driving force for the enrichment of tricyclic terpanes. In such cases, significant oils have been generated and expelled, an early or faster rate of generation/expulsion of hopanes relative to tricyclic terpanes may occurred, which is evidenced by the extended hopanes are depleted in all the studied rock extracts. Furthermore, to our knowledge, the predominance of tricyclic terpanes over hopanes has not been observed in source rocks of the Yanchang Formation in other regions of the Ordos Basin. The observation of the enhanced presence of tricyclic terpanes in the current study may suggest that the hydrocarbon-generating intensity and petroleum expulsion efficiency of source rocks in the Qingcheng area are higher than that of other regions in the basin. Thus, the Qingcheng area has tremendous potential for petroleum resources and is an important area for future exploration.

Tricyclic Terpane Fingerprint of Crude Oils from Niger Delta, Nigeria

Tricyclic terpanes identified in two representative crude oils from the Central and Western Niger Delta (oil- RVAG and oil-DTIR, respectively) ranged from C19 to C29, including C24 tetracyclic terpane. Plot of the abundances of tricyclic terpanes show similarity in the distribution profile of the oil samples, characterized by the uncommon distribution of C20 and C21 tricyclic terpanes indicating both Niger Delta crude oils are derived from similar source organic matter. Ratios of C22/C21 and C24/C23 tricyclic terpanes indicate source rocks of the crude oil samples were deposited in a deltaic environment and derived from mixed marine/terrestrial organic matter. Additional, C26/C25 tricyclic terpanes, C24 tetracyclic/C23 tricyclic terpanes and C24 tetracyclic/C26 tricyclic terpanes indicate the crude oil samples are generated from shale source rocks derived from terrestrial organic matter, with oil-DTIR receiving a more terrestrial contribution, and marine facies, with oil-RVAG receiving a more marine contribution. Thermal maturity, determined from ratios of low to high molecular weight tricyclic terpanes, indicate the crude oil samples are mature with oil-RVAG more mature than oil-DTIR. The ratios of C19/C23 and C20/C23 tricyclic terpanes, which indicate high maturity of the crude oils, suggested terrestrial and marine source for oil-RVAG and oil-DTIR, respectively, contrasting with the relative abundances of tricyclic and tetracyclic terpanes. This implies the abundances of C19 and C20 tricyclic terpanes, particularly in crude oils at high maturity, as in the Niger Delta, has interfering effect on source interpretation and its ratios be used in combination with other parameters for evaluating Niger Delta crude oils.

Chemometric Evaluation of Terpanes for Composition Allocation of Two Niger Delta Crude Oil Mixtures

Chemometric methods were employed to evaluate terpanes that correspond to the variations in the compositions of two Niger Delta crude oils (samples A-10 and F-00) in their mixes (samples B-82, C-64, D-46, and E- 28). Total abundances, plots, and hierarchical cluster analysis of C19 to C35 terpanes in the six oil samples suggest that the abundances and distributions of terpanes significantly correlated and did not mix correspondingly in the oil samples. Principal component analysis (PCA) showed that the first principal component (PC1) accounted for 95.77% of the total variance of individual terpanes among the oil samples with H30, OL, and NH30 explaining the most variance and NH25a, NH25b, and TR20d explaining the least variance, respectively. Plots of nine (9) ratios, derived from the most and least variant terpanes, gave R² values (0.4919 - 0.9749) that indicate the ratios moderately to very strongly correspond to the compositions of the two Niger Delta crude oils in the oil samples. Ratios of H30/H30+NH25b, OL/OL+NH25b and NH30/NH30+NH25b, with the highest R² values, showed very strong predictability (97.33%, 97.03% and 97.49%) for estimating the compositions of the two Niger Delta crude oils in their mixes.

Origin and Characteristics of the Crude Oils and Condensates in the Callovian-Oxfordian Carbonate Reservoirs of the Amu Darya Right Bank Block, Turkmenistan

Abstract The Amu Darya Right Bank Block is located northeast of the Amu Darya basin, a large petroliferous sedimentary basin, with abundant natural gas resources in carbonate rocks under the ultra-thick gypsum-salt layer. Oil fields producing crude oils have recently been found around large gas fields. Unraveling the origins of the crude oils is crucial for effective petroleum exploration and exploitation. The origin of gas condensates and crude oils was unraveled through the use of comprehensively analytical and interpretative geochemical approaches. Based on oil-source correlation, the reservoir forming process has been restored. The bulk geochemical parameters of the local source rocks of the ADRBB indicated that the local sources have hydrocarbon generation and accumulation potential. The middle-lower Jurassic coal-bearing mudstone is gas prone, while the mudstone of the Callovian-Oxfordian gap layer is oil prone, and the organic matter type of Callovian-Oxfordian carbonate rocks is the mixed type between the two previous source rocks. The interpretation schemes for compositions of n-alkanes, pristane and phytane, C27–C28–C29 sterane distributions, C19+C20–C21–C23 tricyclic terpane distributions, extended tricyclic terpane ratio, and δ13C indicated that crude oil is likely from marine organic matter, while condensates mainly originate from terrestrial organic matter. However, from the perspective of the 18α-trisnorneohopane/17α-trisnorhopane and isomerization ratio of C29 sterane, condensates are too mature to have originated in the local source rocks of the ADRBB, whose maturity is well comparable with that of crude oils. The geochemical, geologic, and tectonic evolutions collectively indicate that the crude oils were most likely generated and migrated from the relatively shallow, lowly mature gap layer and Callovian-Oxfordian carbonate rocks of the ADRBB, while the condensates mostly originated from the relatively deep and highly mature middle-lower coal-bearing mudstone and Callovian-Oxfordian carbonate rocks in the Murgab depression in the southeast of the basin. Basement faults are the key factors affecting the types of oil and gas reservoirs. During the periods of oil and gas migration, traps with basement faults mainly captured natural gas and condensates and traps without basement faults were enriched with crude oils generated from local source rocks.

The hysteresis of asphaltene-trapped saturated hydrocarbons during thermal evolution

Asphaltene-trapped (adsorbed or occluded) biomarkers are considered a valid source of information for crude oil with severe secondary alterations. However, thermal stress might change asphaltene-trapped hydrocarbons to some extent. Therefore, it is indispensable to investigate the thermal evolution behavior of asphaltene-trapped biomarkers. In this study, low-maturity bitumen from the Kuangshanliang area of the Sichuan Basin (China) was selected as a sample. The thermal evolution behavior of free and asphaltene-trapped saturated biomarkers was investigated by thermal simulation experiments. The results revealed, in addition to normal biomarkers, also a series of even carbon number n-alk-(1)-enes in asphaltene-occluded hydrocarbons. All of them were hardly influenced by secondary alterations. Moreover, due to the restriction of macromolecular structure, the thermal evolution of asphaltene-trapped biomarkers lags behind that of free biomarkers. Most biomarker parameters of occluded hydrocarbons changed little with increasing maturity. In particular, the distributions of occluded terpanes or steranes retained the characteristics of early diagenesis of organic matter, even if they suffered from strong thermal alteration.

A novel redox indicator based on relative abundances of C31 and C32 homohopanes in the Eocene lacustrine Dongying Depression, East China

A suite of oils and bitumens from the Eocene Shahejie Formation (Es) in Dongying Depression was geochemically characterized to illustrate impact of source input and redox conditions on distributions of pentacyclic terpanes. The Es4 developed under highly reducing, sulfidic hypersaline conditions, while Es3 formed under dysoxic, brackish to freshwater conditions. Oils derived from Es4 are enriched in C32 homohopanes (C32H), while those from Es3 are prominently enriched in C31 homohopanes (C31H). The C32H/C31H ratio shows positive correlation with homohopane index (HHI), gammacerane index, and negative correlation with pristane/phytane ratio, and can be used to evaluate oxic/anoxic conditions during deposition. High C32H/C31H ratio (> 0.8) is an important characteristic of oils derived from anoxic environments, while low values (< 0.8) indicate dysoxic conditions and extremely low values (< 0.4) indicate strong oxic conditions. The C32H/C31H ratio can be applied for deposition condition diagnosis because carboxyl group of C32 hopanoic acids might be reduced to C32 homohopanes under anoxic conditions, and oxidized to C31 homohopane under oxic conditions. Advantages to use C32H/C31H ratio as redox condition proxy compared to the HHI and gammacerane indexes are wider valid maturity range, less sensitive to biodegradation influence and better differentiating reducing from oxic environments.

Geochemical evaluation of produced petroleum from the Middle Permian Lucaogou reservoirs Junggar Basin and its implication for the unconventional shale oil play

The shale of the Middle Permian Lucaogou Formation in the Jimusaer Sag has become one of the most important prospects for unconventional shale oil production in China. The Lucaogou Formation develops two sweet spots, the upper (P2l22) and lower (P2l12) sweet spots, which are not more than 150 m apart. Interestingly, oils produced from the lower sweet spots have higher densities and viscosities than those in the upper sweet spots. Meanwhile, these high-viscosity oils have brought technical challenges to shale oil production. In this paper, geochemical data from 78 source rock solvent extracts and 17 oil samples from various depths were employed to elucidate unconventional petroleum systems and the reason for high viscosities. The source rocks of the Lucaogou Formation are good to excellent, primarily type II and II-III kerogens, and are now in the early-peak oil window. Oils produced from the P2l12 interval are characterized by abundant polar compounds, which are derived from the P2l12 and P2l11 intervals source rocks with relatively high marine sources contribution. Oils in the P2l22 interval are generated from the P2l22 interval source rocks with relatively high terrigenous-marine sources contribution. Terpane biomarker ratios indicate all oil samples are derived from lacustrine source rocks. The distributions of terpanes and steranes in these samples are similar, with high quantities of C29 steranes and low amounts of diasteranes. Migration from sources to reservoirs in the Lucaogou shale oil systems is short-distance given thermal maturity considerations. All oil samples have experienced slight biodegradation (PM level 1–2) at most. The sources and thermal maturities are the primary reasons for the high viscosities of the crude oils produced from the P2l12 interval. This research also indicates the Lucaogou shale petroleum system could be divided into two subsystems, and the production of different unconventional petroleum subsystems requires different strategies.

Organic geochemical characteristics and gas prospectivity of Permian source rocks in western margin of Songliao Basin, northeastern China

The Permian in western margin of Songliao Basin is a strategic potential field of oil and gas resources in northeastern China, but the systematic researches since few boreholes were drilled up to Permian strata, as well as there is a lack of seismic and well-logging data. This paper presents the lithological composition of the Permian Formations on the basis of regional geological survey in western margin of Songliao Basin. A total of 60 mudstones and shales were collected to evaluate the organic geochemical and petrophysical characteristics and gas prospectivity of Permian source rocks. The Permian is composed of Shoushangou, Dashizai, Zhesi and Linxi Formation, which represent large sets of mudstones and shales, which are mainly deposited in a weakly to strongly reducing marine environment. The primary organic matter precursors in Permian were lower aquatic organisms such as zooplankton and algae, while a few samples of Linxi Formation indicate mixed sources of lower aquatic organisms and terrigenous higher plants. The Permian gas–prone source rocks are at over–mature stage with vitrinite reflectance Ro% = 2.01%–3.14% and mainly classified as fair to good quality and type II–III kerogens, and generally have a tricyclic terpane distribution pattern of C21>C23>C20, but Shoushangou Formation and Linxi Formation have subordinate patterns of C21>C20>C23 and C23>C21>C20, respectively. The residual organic matters in Permian source rocks have CH4 yields up to 24.34 mg/g∙TOC at EASY%Ro = 4.45%, which indicate the possibility of secondary gas generation at Ro% = 2.0%–3.5%. The pores and fractures are developed in Permian source rocks with widths of 5.28–18.64 μm, and mean values of porosity and permeability are 2.17% and 0.0043 × 10−3 μm2, respectively. The source–reservoir–cap rock assemblages in Carboniferous–Permian and Mesozoic sedimentary sequences are included in situ and near–source accumulation in Permian, and long–distance migration and accumulation in underlying Carboniferous and overlying Triassic, Jurassic and Cretaceous. The Permian system can be regarded as a potential gas exploration target in the western margin of Songliao Basin.

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.

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.

Transformation of Terrestrial Organic Matter during Mesocatagenesis and Apocatagenesis

Abstract —A combination of modern analytical methods was used to study terrestrial organic matter from upper Paleozoic rocks in the central part of the Vulyui hemisyneclise (East Siberia) sampled from the depth interval 3370–6458 m penetrated in the Srednevilyuiskaya-27 superdeep well. In this study, we used 71 core samples to trace depth variations in the geochemical characteristics of organicmatter during middle–late mesocatagenesis and apocatagenesis: organic carbon content (Corg), Rock-Eval pyrolysis parameters (HI, Тmax), carbon isotope composition, thermal maturity (RVto, %), hydrocarbon type composition (hydrocarbons, resins, and asphaltenes), distributions of n-alkanes (TIC), steranes (m/z 217), and terpanes (m/z 191), and standard biomarker indices with increasing degree of thermal maturity. It is shown that during late mesocatagenesis and apocatagenesis, the pyrolysis parameters and biomarker indicators are no longer effective as indicators of organic-matter maturity and genesis.

Future environmental challenges of the urban protected area Great War Island (Belgrade, Serbia) based on valuation of the pollution status and ecosystem services

The Great War Island (GWI) is an area of importance for the protection of the environment, cultural and historical heritage of Belgrade, Serbia. According to the International Union for Conservation of Nature (IUCN) this area belongs to the IV category - Habitats and Other Regulated Areas. The main objectives of this paper are to evaluate the potential impacts of pollution on ecosystem services of the Great War Island and to explore different scenarios for future urban development of the Great War Island that will have implication for human well-being. The aims of this paper are set up based on the evaluation of ecosystem services of the Great War Island and assessment of the pollution status of the Great War Island. In order to evaluate pollution status of the GWI inorganic and organic composition of sediments were examined. Additionally, the content of microelements was determined in the leaves of the Salix alba L. Pollution indices indicate that all investigated sampling sites are polluted and correspond to high and very high degree of contamination. Cd and Cu show high to extremely high degree of contamination while Sb has extremely high degree of contamination. Content of As, Co, Cu, Ni and Zn in leaves of Salix alba L. is in sufficient to normal range, while content of Cd is between the sufficient and excessive values generalized for various species. Typical oil distributions of terpanes and steranes and values of the corresponding maturity parameters clearly indicated that the sediments of the GWI, in addition to native organic matter, contained oil pollutants of anthropogenic origin. GWI provides provisioning, regulating, supporting and cultural ecosystem services. In relation to ecosystem services two possible scenarios can be predicted: first - losing the status of a protected area due to urbanization; and the second - increasing the degree of protection by admission into international protection lists.

Heterocyclic aromatic hydrocarbon distributions in petroleum: A source facies assessment tool

This study reports a novel source facies assessment application from distributions of heterocyclic aromatic hydrocarbons in petroleum, i.e., dibenzothiophene (DBT), dibenzofuran (DBF) and fluorene (F). To illustrate the approach initially, a large set of crude oils from global petroleum basins are geochemically characterized based on source facies, organic-matter type and environment of deposition variation. Petroleum bulk properties and molecular distributions of isoprenoids, terpanes, steranes and related parameters are applied to demonstrate the source facies and maturity of the entire oil suite and to delineate the oil suite into marine carbonate, marine shale, marine shale with terrigenous organic matter (OM), coaly and lacustrine source-facies families. From within this interpretive context, the relative percentages of hetercyclic aromatic hydrocarbons are reported and discussed from each of these source-facies families. A triplot drawn from the percentages of DBT, DBF and F is shown to effectively differentiate the oils source-facies classifications. Marine carbonate oils show highest %DBT plotted in the DBT vertex, freshwater lacustrine-sourced oils positioned near to 100% F vertex, coaly-sourced oils revealed highest %DBF. The marine shale and marine shale with terrigenous-OM oil families plotted away from three vertices and represent a distinctive position with in the triplot. These results establish an effective source-facies assessment tool triplot based on heterocyclic aromatic hydrocarbon distributions. These novel signatures which are derived from variations in the chemical composition of source rocks, hence kerogen, lead to the occurrence of kerogen catalysis in sedimentary reaction (like carbon catalysis) for the formation of heterocyclic aromatic hydrocarbons.

Depositional environment, organic matter sources, and variable 17α(H)-diahopane distribution in Early Permian samples, southern Sydney Basin, Australia

Early Permian strata exposed in the southern part of the Sydney Basin, NSW, Australia, include the Pebbley Beach Formation, the Snapper Point Formation and the Wandrawandian Siltstone. These formations were deposited during the Late Paleozoic Ice Age, when Australia was close to the South Pole. The Pebbley Beach and Snapper Point formations were deposited in shallow marine to coastal environments, while the Wandrawandian Siltstone was deposited in deeper water following a marine transgression. However, opinions differ on the precise environmental and climatic conditions that prevailed during their deposition. Sixteen outcrop samples from these formations were collected and analysed to determine their depositional conditions and the source(s) of their organic matter.The biomarker and aromatic hydrocarbon distributions show that the rocks are in the early to mid-oil window. Some aromatic parameters show that the stratigraphically younger Wandrawandian Siltstone is more thermally mature than the older Pebbley Beach Formation, which is interpreted to be due to the geographic position of these outcrops in the Sydney Basin. The samples have low to intermediate pristane/phytane ratios (from 1.4 to 3.4), showing variation from oxic to suboxic depositional conditions. Most of the mudstones and siltstones sampled were deposited in a marine environment, with some fluvial-deltaic or estuarine influence, and contain mixed type II and type III organic matter. The Pebbley Beach formation is characterised by terpane distributions dominated by the C24 tetracyclic terpane, and to a lesser extent the C19 tricyclic terpane. The Snapper Point Formation has a mix of C19 and C23 tricyclic terpanes and C24 tetracyclic terpane, while the Wandrawandian Siltstone is dominated by C19, C21, and C23 tricyclic terpanes. The sterane distribution follows a C29 > C28 > C27 pattern in the majority of the samples, including in the marine deposited Wandrawandian Siltstone. The three formations have very variable relative amounts of diahopanes and other rearranged hopanes, with the highest C30*/C30 αβ hopane ratio (6.9) in the Wandrawandian Siltstone. This formation also has high amounts of diasteranes compared to the other two formations, but the relative amounts of diasteranes are not as high as for the diahopanes. Classically, this suggests a clay-rich sediment in an oxic or suboxic, acid-catalysed depositional environment, with enhanced diagenetic alteration of the biomarkers. The Wandrawandian Siltstone was deposited in suboxic conditions, not unusual to many rocks that contain much less rearranged hopanes. Unusual characteristics of the Wandrawandian Siltstone include significant slumping and soft sediment deformation, and deposition under periglacial-glacial conditions. The occurrence of the slumps on the continental slope led to significant sediment overturn, and this may have resulted in enhanced diagenetic and catalytic rearrangement reactions, leading to the elevated levels of diahopanes and other rearranged hopanes. The disequilibrium between the relative abundances of diahopanes and diasteranes suggests different formation mechanisms for these biomarkers.

Geochemical Characteristics of Oil from Oligocene Lower Ganchaigou Formation Oil Sand in Northern Qaidam Basin, China

Oil from the Oligocene oil sands of the Lower Ganchaigou Formation in the Northern Qaidam Basin and the related asphaltenes was analyzed using bulk and organic geochemical methods to assess the organic matter source input, thermal maturity, paleo-environmental conditions, kerogen type, hydrocarbon quality, and the correlation between this oil and its potential source rock in the basin. The extracted oil samples are characterized by very high contents of saturated hydrocarbons (average 62.76%), low contents of aromatic hydrocarbons (average 16.11%), and moderate amounts of nitrogen–sulfur–oxygen or resin compounds (average 21.57%), suggesting that the fluid petroleum extracted from the Oligocene oil sands is of high quality. However, a variety of biomarker parameters obtained from the hydrocarbon fractions (saturated and aromatic) indicate that the extracted oil was generated from source rocks with a wide range of thermal maturity conditions, ranging from the early to peak oil window stages, which are generally consistent with the biomarker maturity parameters, vitrinite reflectance (approximately 0.6%), and Tmax values of the Middle Jurassic carbonaceous mudstones and organic-rich mudstone source rocks of the Dameigou Formation, as reported in the literature. These findings suggest that the studied oil is derived from Dameigou Formation source rocks. Furthermore, the source- and environment-related biomarker parameters of the studied oil are characterized by relatively high pristane/phytane ratios, the presence of tricyclic terpanes, low abundances of C27 regular steranes, low C27/C29 regular sterane ratios, and very low sterane/hopane ratios. These data suggest that the oil was generated from source rocks containing plankton/land plant matter that was mainly deposited in a lacustrine environment and preserved under sub-oxic to oxic conditions, and the data also indicate a potential relationship between the studied oil and the associated potential source rocks. The distribution of pristane, phytane, tricyclic terpanes, regular steranes and hopane shows an affinity with the studied Oligocene Lower Ganchaigou Formation oil to previously published Dameigou Formation source rocks. In support of this finding, the pyrolysis–gas chromatography results of the analyzed oil asphaltene indicate that the oil was primarily derived from type II organic matter, which is also consistent with the organic matter of the Middle Jurassic source rocks. Thus, the Middle Jurassic carbonaceous mudstones and organic rock mudstones of the Dameigou Formation could be significantly contributing source rocks to the Oligocene Lower Ganchaigou Formation oil sand and other oil reservoirs in the Northern Qaidam Basin.

Geochemical research of asphaltite formation in the Orenburg region

The results of the studies of the physicochemical properties and genesis of asphaltites from the deposits of the Orenburg region are considered. Based on the data of a study on the distribution of hydrocarbon biomarkers (n-alkanes, isoprenanes, steranes, and terpanes), it was found that deposit formation occurred in carbonate layers under reducing conditions. The distribution of steranes and terpanes confirmed a sufficient maturity of the asphaltite. The C28/C29 sterane ratio of 0.31 corresponds to Silurian age according to Grantham or to Silurian–Devonian age according to the pregnane coefficient (a ratio of the sum of C21–C22 pregnanes to the sum of C21–C22 pregnanes and C27–C29 regular steranes) of 9.0%. Thus, it is likely that asphaltites from the Ivanovk deposit in the Orenburg region were redeposited in Silurian/Devonian source rock formations.

Diversities in biomarker compositions of Carboniferous–Permian humic coals in the Ordos Basin, China

ABSTRACTThe molecular composition of Carboniferous–Permian coals in the maturity range from 0.66 to 1.63% vitrinite reflectance has been analysed using organic geochemistry to investigate the factors influencing the biomarker compositions of humic coals. The Carboniferous–Permian coal has a variable organofacies and is mainly humic-prone. There is a significant difference in the distribution of saturated and aromatic hydrocarbons in these coals, which can be divided into three types. The Group A coals have biomarker compositions typical of humic coal, characterised by high Pr/Ph ratios, a lower abundance of tricyclic terpanes with a decreasing distribution from C19 tricyclic terpane to C24 tricyclic terpane and a high number of terrigenous-related biomarkers, such as C24 tetracyclic terpane and C29 steranes. The biomarker composition of Group B coals, which were deposited in a suboxic environment, have a higher abundance of rearranged hopanes than observed in Group A coals. In contrast, in Group C coals, the Pr/Ph ratio is less than 1.0, and the sterane and terpane distributions are very different from those in groups A and B. Group C coals generally have abnormally abundant tricyclic terpanes with a normal distribution maximising at the C23 peak; C27 steranes predominates in the m/z 217 mass fragmentograms. The relationships between biomarker compositions, thermal maturity, Pr/Ph ratios and depositional environments, indicate that the biomarker compositions of Carboniferous–Permian coals in Ordos Basin are mainly related to their depositional environment. This leads to the conclusion that the biomarker compositions of groups A and B coals collected from Shanxi and Taiyuan formations in the northern Ordos Basin are mainly related to their marine–terrigenous transitional environment, whereas the biomarker compositions for the Group C coals from Carboniferous strata and Shanxi Formation in the eastern Ordos Basin are associated with marine incursions.

Biomarker geochemistry of crude oils and Lower Paleozoic source rocks in the Tarim Basin, western China: An oil-source rock correlation study

Abstract In order to select biomarker parameters that have potential to quantitatively distinguish between the Cambrian–Lower Ordovician and Upper Ordovician source rocks in the Tarim Basin with a total organic carbon content >0.5%, 42 Lower Paleozoic shale samples, were collected from a number of wells and outcrops in the Tarim Basin, northwestern China. The biomarkers in the extracts of the source rocks were analyzed by gas chromatography–mass spectrometry. The results show that C23 and C30 were dominant in the tricyclic terpanes and pentacyclic triterpanes, respectively, and C27 and C29 were both dominant in C27–29 steranes of the source rock samples. The distribution of n-alkanes, isoprenoids and terpanes indicate that the source rock samples have been slightly to moderately biodegraded, and they originated from a reducing depositional environment with considerable marine algal input in. Comparatively, Upper Ordovician source rock samples presented lower values of C28/C29 regular steranes and higher values of C29 ααα20S/(20S + 20R) and C29αββ/(αββ+ααα). Abnormally lower values of C29 ααα20S/(20S + 20R) and C29αββ/(αββ+ααα) were observed in the Cambrian–Lower Ordovician strata. The set of data in this study show that homohopane index including C31homohopane/C30hopane, C31-35homohopanes/C30hopane, and the ratios related to the triaromatic steroids including C26−20S/C28−20S TAS, C27−20R/C28−20R, (C26−20R + C27−20S)/C28−20S and C28/(C26+C27) TAS, could serve as potential biomarker parameters to distinguish between the two groups of source rocks in the Tarim Basin. The values of those parameters (in above order) in Cambrian–Lower Ordovician source rocks were 0.3, >0.5, >0.85, and 0.8, >1.9, 1.2, respectively. The correlation between the source rock samples and 19 oils obtained from the Tadong, Tabei and Tazhong uplifts in the Tarim Basin show that most of the oils in Tabei uplift are probably from Upper Ordovician source rocks, the oils in Tadong uplift are more likely from Cambrian- Lower Ordovician source rocks, and the Tazhong uplift is more like a mixed oil region with oils from both of the two groups of source rocks.