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This paper presents a small-scale column chromatography method for separating hopanes in crude oil or rock extracts using neutral alumina as a solid phase adsorbent and a Pasteur pipette as a separation device. Three oil samples were selected to study the effect of solid phase adsorbent type and column length on the separation of hopanes. The oil samples were eluted with mixed reagents (V hexane : V petroleum ether  = 8:2) and collected at intervals of 0.5 ml. Ten Fractions were collected and tested for the compounds using GC-MS. A quantitative approach was used to reveal distribution characteristics of compounds in each eluted Fraction. Experimental results showed that 100-200 um neutral alumina exhibited significant differences in the adsorptive capacity of biomarkers from oil samples and rock extracts. The elution order of the biomarkers in the chromatographic column (the length is 180 mm) was n-alkanes, steranes and hopanes. The separation of hopanes could be realized by collecting the eluted Fractions 4 and 5. Compared with the urea complexation, the purity of hopanes separated by column chromatography was higher. The concentration of n-alkanes (nC 16 -nC 34 ) could be reduced from 1.99 to 4.83 mg/ml to 0.79-0.94 mg/ml, and the content of steranes can be reduced from the original 12% to 0.45%. Residual n-alkanes and steranes were not visible in the GC-MS detection. The Total Ion Chromatography (TIC) of hopanes was consistent with the distribution characteristics of the m/z191 mass chromatogram. The isolated hopanes could meet the detection requirements of isotope ratio mass spectrometry. The C 29 Ts/C 29 αβ ratio of hopanes decreased gradually from 1.63 to 0.73 as the column length increased. It is speculated that the variation of the C 29 Ts/C 29 αβ ratio is not only affected by maturity but also by the oil and gas migration. This method is a new attempt in the field of compound purification and can be widely used in the study of stable carbon isotopes of hopanes monomeric hydrocarbons., Competing Interests: Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper., (Copyright © 2022. Published by Elsevier B.V.)

The exceptionally low geothermal gradient (~2 °C/100 m) in the Tarim Basin, notably in the Shuntuoguole (STGL) area with depths exceeding 7000 m, has catalyzed the discovery of ultra-deep liquid hydrocarbons. Yet, the genesis of these hydrocarbons remains elusive, presenting significant challenges to further exploration and development endeavors. To address this quandary, an extensive analysis involving biomarker assessments and compound-specific δ2H and δ13C isotopic evaluations of n-alkanes was conducted, unveiling the secondary alterations and origins of these crude oils. For the first time, an approximately horizontal distribution of compound-specific δ2H and δ13C in n-alkanes was observed. Through the integration of diagnostic biomarker compounds, it was elucidated that the STGL crude oils did not undergo significant biodegradation, thermal alteration, or thermal sulfate reduction. Biomarker- and compound-specific C/H isotopic correlations suggest that the STGL crude oil predominantly originates from the Lower Cambrian calcareous shale, positing it as a potential end-member oil for this lithofacial source rock. Furthermore, the STGL crude oil exhibits similar biomarker configurations (notably abundant C28 triaromatic sterones, C23 tricyclic terpenoids, and aryl isoprenoids, with minimal 4-methylstane and gammacerane presence) to those oils previously considered as mixed from the Tazhong and Tabei Uplifts within the Tarim Basin. This similarity suggests that these previously deemed mixed oils may also derive from the Lower Cambrian calcareous shale. Consequently, more focused investigations into the Lower Cambrian calcareous shale are imperative to bolster refined deep and ultra-deep petroleum exploration efforts within the Tarim Basin in forthcoming studies. [ABSTRACT FROM AUTHOR]

In order to study the geochemical characteristics of fine-grained sedimentary rocks and clarify its relationship with the tight oil reservoir, the Chang7 Member of Triassic Yanchang Formation in Longdong area was taken as an example to be studied by rock pyrolysis, isotopic determination, maceral analysis, gas chromatography and gas chromatography–mass spectrometry. Lacustrine organic-rich fine-grained sedimentary rocks can be divided into organic-rich shale and organic-rich mudstone according to their lithology and texture. The results show that the organic-rich shale was deposited in a quiet and anoxic deep lacustrine environment, the organic matter was of high abundance and mainly sourced from plankton and benthic algae (type I–II1). Organic-rich mudstone mainly deposited in the semi-deep lacustrine environment, where the water was relatively shallow and the salinity was low, the organic matter was of low abundance and came from the mixed source of plankton and terrestrial clastic (type II1–II2). The Chang7 tight oil is widely distributed in the turbidite sand bodies, and it was mainly sourced from the Chang7 organic-rich shale. [ABSTRACT FROM AUTHOR]

In order to establish the distribution pattern of fine-grained sedimentary rocks and clarify the coupling relationship between lacustrine organic-rich fine-grained sedimentary rocks and tight oil reservoir, the Chang7 Member of Triassic Yanchang Formation in Longdong area was taken as an example to be studied by core description and log interpretation, gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS). Lacustrine organic-rich fine-grained sedimentary rocks were divided into shale and mudstone according to their lithology and texture. The results show that the shale is mainly developed in Chang73 Sub-member, while the mudstone is developed in each sub-member of Chang7 Member. The organic-rich fine-grained sedimentary rocks in Bazhu-Maling-Qingcheng-Huachi area are the thickest in Longdong area. During the Chang73 sedimentary period, the shale was widely distributed in the center of the lake. In the Chang72 sedimentary period, the mudstone and turbidite were interstratified and superimposed. During the Chang71 sedimentary period, the mudstone was only distributed as thin layers between the thick turbidite. The Chang7 tight oil is widely distributed in the turbidite sand bodies, and it is mainly sourced from the Chang73 shale. The distribution of tight oil is controlled by the development of organic-rich fine-grained sedimentary rocks. [ABSTRACT FROM AUTHOR]

A suite of oils from the Bongor Basin, South Western Chad was characterized geochemically to investigate the behavior of carbazoles and benzocarbazoles during biodegradation. The oils show similar maturity levels and organic facies type with biodegradation as the primary control on molecular compositions. According to compositional variation, the biodegradation levels of oils fell within PM level 0–8 [PM biodegradation scale (Peters, K.E., Moldowan, J.M., 1993)]. Absolute concentrations of carbazole, methylcarbazoles, C 2 -carbazoles, and benzocarbazoles in the oils show an increase from PM level 1–3, fluctuation at PM level 4–7, and sharp decrease above PM level 7. Relative abundances of the carbazole series indicate that C 0 –C 2 -carbazoles are more susceptible to biodegradation than benzocarbazoles, 2- and 3-methylcarbazoles are more susceptible than 1- and 4-methylcarbazoles, partially shielded dimethylcarbazoles are more susceptible than the exposed ones and both of these are more susceptible than shielded dimethylcarbazoles. Benzo[c]carbazole seems to show a higher ability to resist biodegradation than benzo[a]carbazole in heavily biodegraded oils. Therefore, ratios of 1-/(2-+3-) methylcarbazole, 4-/(2-+3-) methylcarbazole, 1,8-dimethylcarbazole/total dimethylcarbazoles, 1,8-/1,3-dimethylcarbazole, and 1,8-/2,4-dimethylcarbazole may be used to assess the degree of biodegradation in this area. [ABSTRACT FROM AUTHOR]

Gas chromatography fingerprint technique has the advantages of fast performance and low cost. It can be used to conduct analysis without interruption either in the field or at laboratory. This technique has been used successfully in such cases that conventional production logging techniques are powerless. Taking low-concentration anthracene as internal standard, we calculated the absolute concentrations of fingerprints, initially made some experiments directly on biodegradation of crude oils, and calculated production allocation in the Gudong Oil field. Compared with the production logging, this method has made up for the deficiencies of the former GC fingerprint technique. It will find wide applications in monitoring the trend of production in various oil-fields. [ABSTRACT FROM AUTHOR]

An immature humic coal sample from the Yaojie Formation of the Muli coal field is pyrolysed in a hydrous closed system. The differences in aromatic hydrocarbon compositon between bitumens and expelled oils are investigated with the simulation temperature ranging from 250 to 500 °C. The absolute concentrations of the main aromatic classes in bitumens and expelled oils initially increase and thereafter decrease with increasing maturity. The absolute concentrations of naphthalene are always higher in expelled oils than in the corresponding bitumens; however, the absolute concentrations of alkyl-naphthalenes, phenanthrene, and alkyl-phenanthrenes are higher in bitumens than in expelled oils at the lower-maturity stage, and reversals occur with continuous increase in R O. Most of the common parameters—MNR, MPI1, MPR, F 1, and F 2—exhibit regular differences in bitumen–expelled oil pairs. The ratios of different alkylation degrees of naphthalenes and phenanthrenes (such as N/C 1–5 -N, C 1 -N/C 1–5 -N, C 1 -N/C 5 -N, P/C 1–3 -P, and C 1 -P/C 3 -P) and the ratios of aromatic components (such as naphthalene/phenanthrene, phenanthrene/fluoranthene, and phenanthrene/pyrene) that have different numbers of aromatic rings exhibit regular differences in bitumen–expelled oil pairs. These ratios of expelled oils are always higher than those of corresponding bitumens; reversals may occur at a high maturity stage. The systematic differences between the compositions of the main aromatic hydrocarbons in bitumens and expelled oils could be predominantly controlled by the fractionation effect at a lower-temperature stage and differentiated decomposition at a higher-temperature stage during the hydrous pyrolysis of coal. • Fractionation effects of aromatic hydrocarbons during expulsion process have been studied by hydrous pyrolysis of coal. • The fractionation effects occur at lower temperature stage and general reversal occurs at higher temperature stage. • The major control factors are fractionation effect at lower maturity and differentiated decomposition at higher maturity. [ABSTRACT FROM AUTHOR]

• Primary and secondary cracking doesn't overlap under geological conditions. • Maturation yields heavier fluid with lower P sat , and lighter one with higher P sat. • Phase evolution systematics mimic natural petroleum well at similar maturity. For the exploration of shale oil, there is still an urgent need to relate hydrocarbon generation reactions and changing phase behavior to exact levels of thermal maturity. Six organic-rich shale samples from the Cretaceous Qingshankou Formation, Songliao Basin spanning the maturity range with vitrinite reflectance (R o) 0.58%–1.16% were studied for petroleum generation characteristics using the PhaseKinetics, PhaseSnapshot, and GORFit approaches. All samples show very good petroleum potential and contain Type I kerogen with total organic carbon contents ranging between 1.5% and 5%. A full spectrum of light to heavy hydrocarbons, consistent with live oils, occurs in thermal extracts of all samples. Gas chromatography fingerprints of samples with R o > 0.7% closely resemble waxy oils derived from lacustrine organic matter (OM); fingerprints of lower maturity samples are not yet as wax rich. The inferred petroleum type organofacies of all samples is paraffinic high wax with low organic sulfur levels. Hydrocarbon generation from the least mature sample is characterized by one dominant activation energy at 55 kcal/mol, accounting for 87% of the total bulk reaction. Assuming a simplified geological scenario, i.e., a 3 K/My linear heating rate, primary petroleum is generated (transformation ratio, i.e., TR : 10%–90%) over a narrow temperature interval of only 23 °C. Onset (10% TR), maximum (T peak), and completion (90% TR) temperatures and R o values are 141 °C at R o 0.85%, 155 °C at R o 1.08%, and 164 °C at R o 1.2%, respectively. Primary gas generation (148–172 °C) occurs 10 °C later (300 m deeper) than the generation of C 6+ compounds (138–161 °C). Secondary gas formation from oil cracking begins at 182 °C, maximizes at 197 °C, and is completed well before 225 °C (beginning of late gas generation from the secondary cracking of thermally matured, macromolecular organic matter) at 206 °C. Thus, primary and secondary oil cracking processes do not overlap under geological conditions. In line with a paraffinic high-wax oil petroleum type organofacies, cumulative fluids generated from the least mature sample fall within the black oil class over most of the primary kerogen conversion range up to 90% TR as indicated by low saturation pressures (P sat) and gas-oil-ratios generally below 160 Sm3/Sm3. Maturation results in relatively heavy fluids with P sat values in the range 40–70 bar when the free hydrocarbons, i.e., already present prior to pyrolysis, are included, and in lighter fluids with P sat values in the range 70–90 bar, when the free, mostly waxy hydrocarbons, are excluded. Systematics of physical properties and fluid compositions evolution reproduce the general behavior of naturally occurring petroleum sourced from lacustrine OM very well and fit physical properties and compositions of produced shale oils in the Songliao Basin at comparable maturity levels. [ABSTRACT FROM AUTHOR]

The central Junggar Basin in western China is unique because it provides insights into the geochemistry of oil from Jurassic coal measures. The analysis of TOC, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), and carbon isotopes was performed to characterize the oil geochemistry and evaluate the hydrocarbon generation potential of source rocks in a coal-bearing formation. Fluid inclusions, fluorescence microscopy, and burial-thermal history were also used to study the oil generation and charging histories. The results show that the mudstone of the Badaowan Formation is the main source rock of the Jurassic and has relatively high hydrocarbon generation potential. The Jurassic oil in the Zhong-4 Block is moderately mature, with an equivalent Ro of about 0.75%. The oil is characterized by heavy carbon isotopes, a predominance of Pr over the Ph, low abundances of trisnorhopane (Ts), tricyclic terpanes and gammacerane, predominance of C 29 steranes among regular steranes, a preponderance of naphthalene and its alkylated analogues in aromatic compounds, and abundant polycyclic compounds. Such geochemical data indicate a contribution of Jurassic humic type organic matter to the oil. The mudstone in the Badaowan Formation started generating hydrocarbons in the Early Cretaceous and reached the peak of hydrocarbon generation in the middle Cretaceous. One major hydrocarbon charging episode is suggested in the Late Cretaceous and another in the early Neogene. The Fukang Depression in the south is the source kitchen, and oil migrates in a direction of southwest to northeast through faults and sandstone carrier beds. • The Jurassic mudstones and oils are mostly within the oil window. • The mudstone in Badaowan Formation is the primary Jurassic source rock. • Unique biomarker characteristics of the Jurassic oil are demonstrated. • The Jurassic oil shows heavy carbon isotopes (δ 13 C > -28‰). • Two major hydrocarbon charging periods for the Jurassic reservoirs are suggested. [ABSTRACT FROM AUTHOR]

The Tuofutai Bulge in central Tabei of northern Tarim Basin provides insights into the complex geochemical processes of deep oil accumulations. Fifteen crude oil samples collected from deep Ordovician reservoirs were tested and analyzed with light hydrocarbons (LHs) and diamondoids to evaluate the oil family, secondary alteration, and mixing processes. Results show that the oil samples share similar distribution characteristics of LHs and diamondoids and contain low concentrations of methyldiamantanes, suggesting that they belong to one group and have not been significantly altered by thermal cracking. Geochemistry of LHs and diamondoids indicate that the thermochemical sulfate reduction is limited and negligible, whereas some samples are severely altered by biodegradation. The phase fractionation is mainly related to the leakage of light hydrocarbon caused by geological activities such as tectonic uplift and fault activity, and some samples show weak evaporative fractionation. The biodegradation causes the increase in the values of methyladamantane to adamantane (MAs/A) and the concentrations of (1 + 2)-methyladamantane and (3 + 4)-methyldiamantane. The thermal maturity of oil calculated on the basis of LHs and diamondoids is generally higher than that calculated using saturated and aromatic fractions. The difference of various maturity parameters related to saturated hydrocarbon, aromatic hydrocarbon, LHs and diamondoids records multiple oil charging and mixing processes. • Light hydrocarbons and diamondoids of the deep oils was revealed. • The deep oil suffered limited thermal cracking and weak evaporative fractionation. • Significant biodegradation was revealed in some oil samples. • Effect of biodegradation on diamondoid parameter was revealed. • Different molecular maturity indicators reflect multiple charging and mixing. [ABSTRACT FROM AUTHOR]

Abstract: Examination of whole oils and isolated oil acidic fractions using Fourier transform infrared (FT-IR), negative-ion microelectrospray high-field Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR–MS) and gas chromatography–mass spectrometry (GC–MS) reveals significant differences in the functional groups, chemical classes and molecular weights of acidic components in crude oils derived from inland lacustrine source rocks in the Fula Sub-basin, Muglad Basin, Sudan. Correlation of the total acid number value (TAN) and bulk and molecular compositions with reservoir depth (temperature) indicates a strong influence of biodegradation on the origin of the high acidity in the oils and the possibility of distinguishing acidic compounds newly formed by way of in-reservoir biodegradation and those contributed directly from oil degrading bacteria. [Copyright &y& Elsevier]