Source Rock Samples Research Articles

Evolution of the Pristane/Phytane Ratio with Maturity of Lacustrine Source Rocks: Implications of a Thermal Simulation Experiment

The pristane/phytane ratio (Pr/Ph) of source rocks has been extensively used for the identification of paleosedimentary environments and oil–source rock correlations. However, the influences of maturity on the Pr/Ph ratio are not fully understood, which largely limits the applicability of this parameter under geological conditions. Based on a thermal simulation experiment performed on typical lacustrine source rock samples and systematic research on geological source rock samples, the evolution of the Pr/Ph ratio with increasing maturity was investigated in this study. The results indicate that the Pr/Ph ratios of the two source rock extracts progressively decrease with increasing maturity, and the decrease in this parameter is more significant for shallow lacustrine samples than for deep lacustrine samples. The Pr/Ph ratios of the two types of source rocks are different at the oil generation stage with EasyRo less than 1.02% but are similar at the oil cracking stage with EasyRo larger than 1.02%. The Pr and Ph of source rocks are contributed by both biogenic and thermal origins, which are largely determined by the sedimentary environment and maturity, respectively, and the contributions of the two origins are diverse at different maturity stages. The Pr/Ph ratio is mainly controlled by the sedimentary environment at the diagenetic stage, by both sedimentary and thermal maturity at the oil generation stage, and by thermal maturity at the oil cracking stage. The Pr/Ph ratio of source rocks can be used to identify sedimentary environments and oil–source rock correlations at diagenetic and oil generation stages.

Correlation of Neogene Oil and Paleogene Source Rocks in the Middle Huanghekou Sag, Bohai Bay Basin

Several billion-ton Neogene oil fields have been successfully discovered in the middle Huanghekou sag over the past few years. However, the source of the crude oil needs to be clarified, and the relevant oil-source correlation was less carried out. Six source rocks of the third member of the Paleocene Shahejie Formation (Es3) from five wells and sixteen Neogene crude oil samples from nine wells in the middle Huanghekou sag were investigated for the oil-source correlation with the biomarkers and carbon and hydrogen isotopes of saturated hydrocarbon monomers. The distribution characteristics of n-alkanes, C19/C23 ratio of tricyclic terpanes, long-chain tricyclic terpene ratios (ETR), C24 tetracyclic terpane to C26 tricyclic terpene, and distribution characteristics of conventional steranes suggest that the Es3 parent material is of a mixed-source input from terrestrial higher plants and aquatic phytoplankton. The gammacerane to C30 hopane ratio is low, ranging from 0.094 to 0.134, with a mean value of 0.118; the Pr/Ph ratio is less than 1.5. The Neogene oils show the characteristics of a saturated hydrocarbon biomarker similar to Es3. The carbon and hydrogen isotopes of saturated hydrocarbon monomers also corroborate the oil-source correlation from the depositional environment and parent material source, which characterize the low salinity of the water during the Es3 sedimentary period, which was a brackish or a freshwater delta deposition under weak oxidation–weak reduction conditions. The parity dominance of CPI and OEP values (both greater than 1), higher ratios of Ts/Tm (1.174 to 1.383, mean 1.278) and the C29Ts/C29 norhopane, high values of diahopane and diasterane contents (C30diaH/C30H, C27diaS/C27S), and hopane and sterane isomerization parameters (%22S, %20S, %ββ) confirm that the Es3 source rock samples are mature enough to provide crude oil for the middle Huanghekou sag. The biomarker characteristics of regional Neogene crude oil are significantly different from those of Es4 source rocks in the surrounding depressions (sags), indicating the Es4 strata’s absence in the middle Huanghekou sag. Suitable traps need to be discovered around the hydrocarbon-generating center of the Es3 source rock for oil and gas exploration in the future.

Geochemical Characteristics and Evaluation Criteria of Overmature Source Rock of the Laiyang Formation in Well LK-1, Riqingwei Basin, Eastern China

Total organic carbon (TOC) and hydrocarbon generation potential (Pg) are essential parameters for the qualitative evaluation of source rock and the basis for evaluating hydrocarbon resources in petroliferous basins. However, there will be some deviations in evaluating hydrocarbon resources of overmature source rock by using TOC and Pg. The super-thick overmature source rock of the Early Cretaceous Laiyang Formation was found in well LK-1, the Riqingwei Basin. To accurately understand the oil and gas potential of the Riqingwei Basin, this paper conducted a systematic organic geochemical analysis of the overmature source rock of the Early Cretaceous Laiyang Formation found in well LK-1. Combined with the results of previous thermal simulation tests on hydrocarbon generation of low-maturity samples in the Jiaolai Basin, the original total organic carbon (TOC0) content of source rock in well LK-1 was recovered and the evaluation criteria of overmature source rock was established. Results: (1) The average TOC content of well LK-1 source-rock samples is 1.25 wt.%, and the average Pg content is 0.11 mg/g. The type of organic matter is mainly type II2, including a small amount of type II1 and type III. The average reflectance of vitrinite (Ro) is 4.35%, which belongs to overmature source rock of a poor–fair level and mixed kerogen. (2) After recovery calculation, these samples’ original hydrocarbon generation potential (Pg0) contents ranged from 0.63 to 108.1 mg/g, with an average value of 6.76 mg/g. Furthermore, the TOC0 contents of the analyzed source-rock samples ranged from 0.62 to 30.6 wt.%, with an average value of 2.01 wt.%. It belongs to fair–good source rock, showing better hydrocarbon generation potential. (3) According to the relationship between the Pg0, Pg and TOC content, the evaluation standard for overmature source rock in well LK-1 was established. Under the evaluation standard of overmature source rock, a source rock with a TOC content exceeding 0.6% and a Pg content greater than 0.1 mg/g can be identified as a good source rock. This paper provides a foundation for the fine classification and evaluation of the overmature source rock of the Riqingwei Basin.

Multi-analytical Approach (FTIR, XRF, XRD, GC-MS) Characterization of Source Rocks from the Anza Basin, Kenya

Potential source rocks from three wells (Chalbi-3, Sirius-1, and Ndovu-1) in the Anza Basin of northeastern Kenya were analyzed using elemental carbon-hydrogen-nitrogen analysis, and mineralogical characterization by X-ray diffraction (XRD), X-ray fluorescence (XRF), Fourier transform infrared spectroscopy (FTIR), and scanning electron microscopy (SEM-EDX).)<strong>. </strong>A Gas Chromatography-Mass Spectrometry (GC-MS) analysis of the saturated aliphatic biomarkers was carried out to illuminate the organic matter source. The analytical results revealed that the source rocks have moderate to high total organic carbon (%TOC) content, suggesting conditions in the Basin favor organic production and preservation. The Hydrogen Indices (HI: 0.19–0.60 atomic ratios) typify a predominance of mixed type II/III (oil/gas-prone) with more type III (gas-prone) and less II (oil-prone) kerogens. The FTIR, XRF, and XRD results reveal that the studied source rock samples comprised mainly of quartz, followed by silicate-clay minerals and calcite minerals. The solvent-extractable organic matter investigation revealed biomarker distributions of n-alkanes and isoprenoids (pristane/ phytane ratios), suggesting that source rocks were derived from algae and bacteria deposited weakly anoxic and low toxic environmental conditions, with minimal contribution from terrestrial organic matter sources. Consequently, all three wells have hydrocarbon generation potential, particularly Ndovu-1, which displays good organic matter content to produce oil and gas. The hydrocarbon potential is excellent and capable of making expulsions of oil and/or gas from the wells at sufficient depths.

Hydrogen, carbon dioxide, and methane adsorption potential on Jordanian organic-rich source rocks: Implications for underground H2 storage and retrieval

Hydrogen (H2) storage in geological formations offers a potential large-scale solution suitable for an industrial-scale hydrogen economy. However, the presence of organic residuals can significantly influence the H2 storage efficiency, as well as cushion gas performance, such as CO2 and CH4, injected to maintain healthy reservoir pressure. Thus, the H2 storage efficiency and cushion gas selectivity were thoroughly investigated in this work based on H2, CO2, and CH4 adsorption measurements using, for the first time, actual organic-rich carbonate-rich Jordanian source rock samples (TOC = 13 % to 18 %), measured at 60 °C temperature and a wide range of pressure (0.1 – 10.0 MPa). Initially, the samples were characterized using various analytical methods. Results demonstrated that H2 adsorption capacities reached up to 0.47 mol/kg at 9.0 MPa. The measured adsorption of CO2 was four times higher than H2. An increase in TOC significantly decreased H2 adsorption compared to CO2 and CH4. Additionally, CO2 demonstrated preferential behavior as a cushion gas compared to CH4, attributed mainly to the calcite content and presence of carboxyl and sulfonyl groups. This study provides fundamental data for understanding H2 potential storage issues in an organic-rich rock formation and thus aids in the industrial implementation of an H2 supply chain.

New insight into geochemical characterization of Paleogene coals from Jarain coalfield, Meghalaya, N-E India: Hydrocarbon potential and organic petrographic analysis

In the present work, geochemical techniques such as Rock-Eval pyrolysis, TOC, Organic petrographic analysis, and statistical investigation have been performed to conclude hydrocarbon generation potential and thermal maturity of studied source rocks samples. Thermal maturity measurement of source rock samples has been assessed by calculated VRo and pyrolysis temperature Tmax (400–418 °C). The result demonstrates that samples are thermal immature in nature and cannot produce hydrocarbons at the commercial level. Modified Van Krevelen diagram (HI versus Tmax) and hydrogen indices (HI) plotted against OI. The study of samples demonstrates that Type II and mixed Type II-III kerogens exist in almost all investigated samples; the HI varies from 203 to 447 mg HC/g TOC and thus can be considered fair oil source and gas/oil source rock. The plot between HI vs Tmax also evaluated the above result. The result of HI vs Tmax is also confirmed by the hydrocarbon richness value (S2/S3), which indicates the emphatic possibility for oil and gas generation in all studied samples. The ternary diagram obtained from microscopic petrographic data typifies that coal forms in platform regions during the coalification process under alternating oxic and anoxic moor conditions. The finding of statistical techniques like Pearson's correlation and cluster analysis also demonstrated that the source rock has tremendous potential for producing hydrocarbons, with a negative correlation between TOC and HI and a decent association between S2 and HI.

Source rock characteristics and 1D basin modeling of the lower Cretaceous Latrobe Group, Gippsland Basin, Australia

The aim of this study is to perform source rock characterization of the Lower Cretaceous Latrobe Group's formations in the Gippsland Basin. A total of 138 source rock samples with coal and shale lithologies were selected from three formations represented by Chimaera, Curlip and Kipper Shale formations. The geochemical analyses consisting Rock-Eval pyrolysis, total organic carbon (TOC), vitrinite reflectance (% VR), maceral composition, and biomarkers were used for source rock characterization of the studied formations. It can be interpreted that the formations have poor to very good TOC (average of 2.32 wt %) indicating good organic abundance, while the coal samples from Chimaera Formation have higher organic abundance with excellent TOC (average of 45.25 wt %). These indicate good hydrocarbon generative potential. The formations mostly generate type II/III (mixed) to type III (gas prone) kerogens. Maturity parameters including production index (PI), temperature of maximum pyrolysis (Tmax), % VR and carbon preference index (CPI) indicated that the source rocks are immature to late mature (oil to oil/gas windows). Paleodepositional environment of source rocks is evaluated with biomarker data – normal alkane distribution, pristane/phytane (Pr/Ph) and isoprenoid/normal-alkane ratios. The results show that the source rocks are dominantly terrestrial, deposited in oxic setting. The rock samples did not show any sign of hydrocarbon migration, but experienced biodegradation. However, biomarker analyses were only done on the Chimaera Formation and the results do not represent the whole source rocks in this study. 1D basin modeling was done for Kipper wells. The results show that in Kipper-1, the oil and gas generations started in Kipper Shale at depths 1900 m about 24 Ma, and 2510 m about 15.4 Ma, respectively. In Kipper-2, oil and gas generations started in Chimaera Formation at depths 2540 m about 8 Ma, and 2580 m about 2.5 Ma, respectively. Transformation ratio (TR) plots show that the oil and gas generations have not reached the peak. Petroleum system event (PSE) chart suggested that the main hydrocarbon generation of the Latrobe Group started 26 Ma and is simultaneously being preserved in the Gippsland Basin. This study hopes to give insight of the burial history concept, hydrocarbon generation, and give support in the development of the hydrocarbon fields in the Gippsland Basin.

Geochemical characteristics of source rocks and gas exploration direction in Shawan Sag, Junggar Basin, China

In recent years, significant advancements have been achieved in the exploration of natural gas around Shawan Sag in the Junggar Basin. However, the geochemical characteristics and distribution of source rocks in the center of the sag have yet to be thoroughly researched, and there is a lack of understanding regarding the evolution history of hydrocarbon generation and the characteristics of each set of source rocks. This has posed limitations on future exploration and development initiatives in the area. The study focused on source rock samples from the uplift zone and conducted a comprehensive evaluation through seismic and hydrocarbon generation thermal simulation experiments. This allowed for clarification of the product characteristics of source rocks in different strata and pointing out the direction for future natural gas exploration. The results showed the presence of four sets of well-developed source rocks in Shawan Sag, characterized by their extensive thickness, wide distribution, and deep burial, laying a material foundation for oil and gas accumulation in peripheral structures. The Carboniferous and Jiamuhe Formation source rocks have high organic matter abundance, but the quality is poor and the potential for generating hydrocarbons is low, leading mainly to the generation of dry gas. On the other hand, the Fengcheng Formation and Lower Wuerhe Formation source rocks have high organic matter abundance and good quality, and are highly mature, resulting in high potential for generating hydrocarbons. The δ13C1-RO regression equation of natural gas in Shawan Sag was established, and the carbon isotope distribution patterns of ethane generated from source rocks in different layers were identified, providing a foundation for determining the maturity of natural gas and correlating the sources of gas in surrounding structures. The west slope of Shawan Sag has favorable preservation conditions and is located on a hydrocarbon migration pathway, similar to the slope of Mahu Sag. This area also has favorable geological conditions for the formation of large lithologic reservoirs, making it a key field for gas exploration in the study area moving forward.

Geochemical characteristics and implications of hydrocarbon in source rocks of Chagan Sag, Yin'e basin of Inner Mongolia

Chagan Sag is one of the most significant tectonic unit in the Yin'e Basin. The special component of the organic macerals and biomarkers in the Chagan sag suggests great difference of its hydrocarbon generation process. In this paper, forty samples of source rocks are subjected to carry out on the geochemical characteristics by methods of rock-eval analysis, organic petrology and gas chromatography mass spectrometry (GC-MS) to reveal the origin, depositional environment and maturity of organic matter in Chagan Sag, Yin'e Basin of Inner Mongolia. The total organic matter of the analyzed samples ranges from 0.4 wt%∼3.89 wt% with an average of 1.12 wt%, indicating fair to excellent hydrocarbon generation potential. The rock-eval results show that the S1+S2 and hydrocarbon index range from 0.03 mg/g∼16.34 mg/g (avg.3.6 mg/g) and 6.24–521.32 mg/g (avg. 199.63 mg/g), suggesting most of the kerogen types are type II and III, with small amount of type I. The Tmax ranges from 428 to 496 °C, suggesting low mature to mature stage. The macerals component of morphological macerals presents with certain amount of vitrinite, liptinite and some inertinite. However, the amorphous component takes the dominant part of the macerals with account of 50%–80%. The amorphous components are dominated by sapropelite in the source rock, indicating bacteriolytic amorphous promote the organic generation process. Hopanes and sterane are widely distributed in the source rocks. The biomarker results suggest a mix of planktonic-bacterial and higher plant origins, with wide range of thermal maturity and relatively reducing depositional environment. Abnormal high content of hopanes were observed in the biomarkers, and some special biomarkers such as monomethylalkanes, long-chain-alkyl naphthalenes, aromatized de A-triterpenes, 8,14-seco-triterpenes, and A, B-cyclostane are detected in Chagan Sag. The presence of these compounds suggests that bacterial and microorganisms are of great significance to the generation of hydrocarbon in the source rock in Chagan Sag.

Differences in geochemistry and hydrocarbon generation of source-rock samples dominated by telalginite and lamalginite: A case study on the Permian saline lacustrine source rocks in the Jimusaer Sag, NW China

The Middle Permian Lucaogou Formation in Northwestern China mainly contains typical saline lacustrine oil shale. To study the differences in geochemistry and hydrocarbon generation of source-rock samples in Lucaogou Formation in Jimusaer Sag, 57 core samples from two boreholes were analyzed herein by performing total organic carbon (TOC) analysis, Rock–Eval pyrolysis, and gas chromatographic–mass spectrometry experiments on saturated hydrocarbons. The kinetics of oil generation were studied using two samples comprising typical maceral components. The results showed that the hydrocarbons produced by telalginite are relatively rich in pristane (Pr), phytane (Ph), β -carotane, high-carbon normal alkanes, and C 29 regular steranes. Hydrocarbons produced by lamalginite contain a significantly higher content of C 20 tricyclic terpanes (TT), C 21 TT, C 24 tetracyclic terpanes (TeT), C 29 norhopane, and C 28 regular sterane. Based on the pyrolysis and biomarker compound parameters, telalginite has a higher conversion rate for hydrocarbons than lamalginite in the low-mature to mature stage, which is consistent with their kinetic analysis. Lamalginite source rock display a much narrower distribution of activation energies than telalginite source rocks; Such narrower activation energy distribution effectively narrows the main stage of hydrocarbon generation. In addition, the activation energy distribution of lamalginite is concentrated in the high-value interval, indicating the characteristics of the relatively lagging hydrocarbon generation of lamalginite.

Thermal Maturity and Kerogen Type of Badenian Dispersed Organic Matter from the Getic Depression, Romania

The aim of this study is to evaluate the thermal maturity of Upper Badenian (Middle Miocene) petroleum source rocks of the Getic Depression, Romania, and to characterize the dispersed organic matter using organic petrography associated with Rock-Eval pyrolysis. A total of 33 core samples of Upper Badenian source rocks from the central–southern part of Getic Depression was studied. The results show that most samples with values of total organic carbon (TOC) < 1% wt.% have a limited potential of hydrocarbons (HC) generation, and 30% of samples with TOC < 1.82 wt.% and kerogen type III, presenting particularly gas generation potential. In three samples from the Bibești, Grădiște and Socu structures the kerogen type III-II was identified, indicating the capability of oil and gas generation. The Badenian source rocks are thermally immature, as few samples are in the pre-oil window, with values of vitrinite reflectance (VRo%) ranging between 0.41% and 0.55%, and the values of Tmax between 409 °C and 443 °C. Optical microscopy with reflected white light and fluorescence blue light was used for identification of terrigenous macerals (vitrinite, liptinite as, resinite, cutinite, sporinite, and inertinite) associated with marine liptinite macerals (telalginite and lamalginite) showing yellow and bright–yellow epifluorescence.

Chemometric recognition of oil–source in the western the Ordos Basin, China

In recent years, significant breakthroughs in the exploration and development of tight oil in the Lower Triassic Yanchang Formation of the Ordos Basin have been achieved. However, there is still a lack of genetic relationship analysis of oil sources in this basin on a large scale. In this study, we performed Rock–Eval pyrolysis to analyze 41 source rocks in four study areas. A total of 79 crude oil and source rock samples from this region was analyzed using gas chromatography mass spectrometry to identify the geochemical characteristics of crude oil and source rocks. Based on 16 biomarker parameters, we used principal component analysis and multidimensional scaling for the analysis of the crude oil source. Combined with alternating least squares, we quantitatively calculated the contribution rate of source rocks to crude oil. The results indicated that the region can be divided into four types of oil sources: the Habahu area in the northwest of the basin, the Huanxian area in the west of the basin, the Pengyang area in the southwest of the basin, and the center of basin. The oil–source comparison results reveal that the reservoirs in the central basin are of single crude oil, whereas those in the Habahu, Huanxian, and Pengyang areas are mixed crude oil. Based on ALS, the relative contribution rates of source rocks in each area to different samples were determined. The present research provides us with a valuable method to use a variety of chemometrics methods to jointly judge the crude oil source and the classification of gene groups.

Organic Geochemistry and Hydrocarbon Generation Characteristics of Shale of the Fourth Member of Yingcheng Formation in the South Shuangcheng Fault Depression, Songliao Basin

In order to evaluate the potential for oil and gas resources in the deep fault depression of the Northern Songliao Basin, shale from the fourth member of the Yingcheng Formation (K1yc4) in the South Shuangcheng Fault Depression was selected as an example. The organic geochemical characteristics such as abundance, type and maturity from experiments on low-maturity source rock samples, the hydrocarbon generation conversion rate, hydrocarbon generation amount and hydrocarbon generation period of the shale from K1yc4 were evaluated via the chemical kinetics method. The hydrocarbon generation threshold of shale from K1yc4 in the South Shuangcheng Fault Depression was analyzed by examining the organic matter (OM) in shale core samples from K1yc4. Based on the thermal simulations to an approximate buried depth of 750 m, the maximum oil-generation stage corresponds to an approximate buried depth of 1380 m. The amounts of generated oil and gas from the shale in K1yc4 are approximately 2.417 × 108 t and 0.546 × 1011 m3, respectively. The shale in K1yc4 generated crude oil mainly during the sedimentary period of the Qingshankou Formation, Yaojia Formation and Nenjiang Formation, and mainly generated natural gas during the sedimentary period of the Nenjiang Formation. In the South Shuangcheng Fault Depression, the high parts of the local structure are the favorable areas for oil and gas exploration of K1yc4 in the sag zone, which could be used for the combined production of shale oil, tight sandstone oil and conventional oil.

Biomarkers and Carbon Isotope of Monomer Hydrocarbon in Application for Oil-Source Correlation and Migration in the Moxizhuang-Yongjin Block, Junggar Basin, NW China.

Different opinions on the oil-source correlation and migration of the Moxizhuang-Yongjin block in the Junggar Basin, NW China, have seriously affected oil and gas exploration in this area. This research is based on the results of biomarker analysis and carbon isotope of monomer hydrocarbon on crude oil and source rock samples from different blocks. Two oil families (A1, A2, and B) are classified by cluster analysis on nine typical biomarker ratios. Typically, sub-family A1 oils are distributed in the Zhuang 102 well block of the Moxizhuang block, and their gammacerane index is the highest. The abundance of C24 tetracyclic terpanes is the lowest, the C27 regular steranes are dominant, and the organic matter is mainly input by lower aquatic organisms. Sub-family A2 oils are distributed in the Zheng 1-1 well block of the Moxizhuang block. The gammacerane index of oils is lower than the former, and the abundance of C24 tetracyclic terpanes is higher. In the dual input of lower aquatic organisms and terrestrial higher plants, the input of terrestrial higher plants accounted for a larger proportion. Family B oils are distributed in the Yong 2 well block of the Yongjin block, and their gammacerane index is the lowest. They have a high abundance of C24 tetracyclic terpanes, and C29 regular steranes are dominant, reflecting the characteristics of terrigenous organic matter contribution. Based on the biomarker compound composition, at least two oil charges are indicated: Sub-family A1 oils are likely sourced from the Wuerhe formation, sub-family A2 oils may be a mixture of Wuerhe formation and Badaowan formation, and family B oils are likely sourced from the Badaowan formation. The oil families with typical genetic affinities may indicate two major petroleum systems or multiple oil systems existing in the study area. In addition, the characteristics of hydrocarbon accumulation and migration are also discussed, the oil and gas in the West Sag of Well Pen 1 and Changji Sag are filled from deep to shallow in the vertical direction and migrated from south to north in the horizontal direction, at the same time, with the help of sand bodies and faults, and they migrated to the north and northeast. This work provides a scientific basis for oil and gas exploration in the hinterland of the Junggar Basin.

Insights into organic metagenesis using Raman spectroscopy and high resolution mass spectrometry: A case study of the Shahezi formation, deep Songliao basin, China

The maturity of sedimentary organic matter is a key parameter for evaluating oil and gas resources. Existing maturity indicators have different evaluation principles and application scopes. This study investigated samples of high to overmature lacustrine source rocks (Ro = 1.33%–4.24%) from the deep Shahezi formation in the Songliao basin, including the zone of catagenesis and metagenesis. Various methods, including vitrinite reflectance, Tmax, laser Raman spectroscopy, and Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) were used to evaluate the samples' maturity. Through laser Raman analysis of representative samples from the Shahezi formation, most laser Raman parameters showed an inflection point or reversal when the thermal evolution of deep source rocks in the Shahezi formation reaches a certain stage. The variation trend of some Raman parameters and Ro has strong regularity (1.33% < Ro < 3.52%). Based on FT-ICR MS, this research analyzed the relative content and molecular composition of polycyclic and heterocyclic aromatic compounds in soluble organic matter of lake source rock samples and comparison samples (marine shale). Quantitative maturity evaluation of organic matter was performed by converting the signal intensity of each compound. The fitting results of maturity parameter based on FT-ICR MS and Tmax indicated that the maturity parameter of the samples have high coefficient of correlations with maturity in the vitrinite reflectance (Ro) range of 1.33%–2.5% and the Tmax range of 420 °C–600 °C. The maturity parameter values decreased as Ro exceeded 2.5% and Tmax exceeded 600 °C. These findings are attributed to the thermal stability of organic compounds and the formation of pyrobitumen and graphite. The parameters of laser Raman spectroscopy also confirmed the growth of aromatic rings reflected by the maturity parameters of FT-ICR MS. These two methods revealed the structural changes of organic matter in the thermal evolution process from multiple perspectives and provided insights for the maturity evaluation of deep source rocks.

Source rock geochemistry of central and northwestern Niger Delta: Inference from aromatic hydrocarbons content

The influence of origin, depositional environment and thermal maturity of organic matter on the occurrence of aromatic hydrocarbons in source rocks from the central and northwestern Niger Delta was investigated. Eighty two source rock samples from four oil wells in the central and northwestern Niger Delta were analyzed for the aromatic hydrocarbon content using gas chromatography-mass spectrometry (GC-MS). The results of analysis of aromatic hydrocarbon fractions of the source rock extracts show the presence of many classes of aromatic hydrocarbons, which include naphthalenes, phenanthrenes, biphenyls, dibenzothiophenes and fluorenes. Trimethylnaphthalene (TMN) is the most abundant among the naphthalenes while dimethylphenanthrene (DMP) is the most abundant among the phenanthrenes. Among the biphenyls, 3-methylbiphenyl (3 MB) is the most abundant while 4-methyldibenzothiophene (4MDBT) is the most abundant among the dibenzothiphenes. Only two fluorenes were detected, and fluorene is more in abundance than 1-methylfluorene (1 MF). Depositional environment indicators of aromatic hydrocarbon organic matter reveal that the organic materials in the source rocks in these wells were deposited in marine-to-swamp depositional environments under reducing to suboxic conditions. Thermal maturity indicators calculated from the abundance of the aromatic hydrocarbons indicate that the source rock samples are thermally mature. Most of the source rocks are at the peak of oil window while a few at the early oil window. Source rocks from wells GB, OP and OT in the central Niger Delta are thermally more mature than those from well AW in the northwestern Niger Delta.

Identification and geochemical significance of unusual C24 tetracyclic terpanes in Shahejie Formation source rocks in the Bozhong subbasin, Bohai Bay Basin

C 24 tetracyclic terpanes are common compounds in source rocks and crude oils, and C 24 17,21-secohopane is the most common and widely used source-related indicator. In this study, three unusual C 24 tetracyclic terpanes were detected on the m/z 191 chromatogram of saturated hydrocarbons in the Shahejie Formation source rocks in the Bozhong subbasin. Based on the mass spectra characteristics, diagnostic ion fragments, retention time and comparisons with published literature, three unusual C 24 tetracyclic terpanes were identified as 10β(H)-des-A-oleanane, 10β(H)-des-A-lupane and C 24 des-A-hopane. To the best of our knowledge, this is the first study to detect and publicly report these three compounds in source rock samples from the Shahejie Formation of the Bozhong subbasin, Bohai Bay Basin. The results indicated that 10β(H)-des-A-oleanane and 10β(H)-des-A-lupane likely originated from terrestrial angiosperms, while C 24 des-A-hopane likely originated from prokaryotic organisms. Terrestrial angiosperms provide the material basis for the generation of compounds A and B, and the distribution and concentration of these two compounds are affected by thermal maturity. In the low maturity stage (0.5% < R o < 0.7%), compounds A and B are relatively enriched in the source rocks.

Origin of organic matter and depositional characteristics of early Cambrian Niutitang Formation from South China: New insights using molecular fossils

The early Cambrian Niutitang Formation is broadly developed in South China, especially in the Yangtze region. This research explains the nature of hydrocarbons through bitumen fractions of the early Cambrian sediments of the Niutitang Formation. For this purpose, source rock samples from two diverse outcrop sections are utilized for total organic carbon content (TOC), solvent extraction, and gas chromatography–mass spectrometry (GC–MS). Results show a lower quantity of extractable organic matter in these older sediments because of higher maturation history. The presence of monomethyl alkanes suggests the contribution of prokaryotic organisms, whereas the presence of hopanoids and C27–C29 steranes shows the occurrence of eukaryotic algal sources in organic matter. Likewise, C30‐4‐methyl sterane, dinosteranes, and ß‐carotene also suggested incorporating prokaryotic and eukaryotic sources during the early Cambrian period. Various hopanoid parameters, alkylated aromatic isomers, triaromatic steroids, and vitrinite reflectance via methyl‐phenanthrene index reveal mature to higher thermal evolution levels of these lower Palaeozoic sediments. Similarly, a higher abundance of polyaromatic pyrene and fluoranthene indicates mature organic matter, and their presence could be due to hydrothermal action. The higher gammacerane index, lower pristine/phytane, and the presence of C30 dimethyl steranes indicate the anoxic saline sedimentary condition throughout the deposition of these lower Palaeozoic Niutitang Formation. The early Cambrian Niutitang Formation is deposited in an oxygen‐deficient environment and contains an adequate amount of mature‐high mature organic matter that could have the potential to produce gaseous hydrocarbons.

Physical properties of lacustrine shale oil: A case study on the lower member of the Lucaogou Formation (Jimusaer Sag, Junggar Basin, NW China)

Shale oil generated by the lower member of the Lucaogou Formation, which was deposited under saline lacustrine conditions within the Jimusaer Sag of the Junggar Basin (NW China), is generally characterized by high density and viscosity. However, a strong spatial heterogeneity of physical properties is observed as well. In this paper, these spatial variations and their controlling mechanisms are evaluated from the perspective of the primary depositional environment, source rock thermal evolution and fractionation effects of primary migration. Based on a detailed organic petrological and geochemical characterization of the target interval within the key well JHBE, hydrous pyrolysis experiments conducted on representative source rock samples from well JHBE, as well as established methods of oil-source correlation subjected to oil samples from several regionally distributed producing shale oil wells, a predictive model of density and viscosity changes of crude oil was established. According to the findings of this study, the thermal evolution and sedimentary environment of source rocks are the main factors affecting the quality of crude oil, and the fractionation effect of primary migration has little effect. Crude oil density and viscosity at first increase up to peak oil maturity, followed by a decrease with further increasing thermal evolution of the source rock. Furthermore, if the source rocks experienced similar thermal histories, it was discovered that relatively low density and corresponding viscosity values are characteristic for crudes from source rocks which were formed in a relatively high salinity environment. In contrast, hydrocarbon generation of source rocks formed under relatively low salinity environments is slightly retarded in direct comparison, and the density and viscosity of the generated crude oil are both relatively high. This highlights that a detailed organic petrographical and geochemical evaluation of the target formation is crucial for the assessment of shale oil potential and production sweet spots in alginite-dominated lacustrine sedimentary environments.

Organic Geochemistry and Oil-Source Correlation of Oil Seepages and Potential Source Rocks in Qiangtang Basin, China.

Different viewpoints on the oil-source correlation of the Angdarco paleo-reservoir in the Qiangtang Basin, northern Tibet, China, have seriously affected oil and gas exploration in this area. In this work, based on the results of biomarker analysis on six oil seepage samples and 11 potential source rock samples, the oil source of the oil seepages in the Angdarco area was examined by correlating the composition characteristics of n-alkanes, multiple factors of biomarkers, correlograms of biomarker parameters, and δ13C values of individual n-alkanes between oil seepages and potential source rocks. In addition, the sedimentary environment and thermal maturity characteristics of the potential source rocks were also discussed. The biomarkers indicated that the potential source rocks of the Lower Jurassic Quse Formation (J1q) presented characteristics of littoral sediments, deposited under suboxic conditions, while the potential source rocks of the Middle Jurassic Buqu Formation (J2b) were deposited in a marine sedimentary environment and presented characteristics of a low mature to mature stage. The potential source rocks of the Middle Jurassic Xiali Formation (J2x) were deposited in a low-salinity environment and presented characteristics of low-mature source rocks. Finally, the oil seepages of the Buqu Formation were deposited in a suboxic littoral environment and presented characteristics of a low mature to mature stage. It is concluded that the oil seepages in the Angdarco paleo-reservoir were mainly sourced from the Lower-Jurassic Quse oil shales. This work provides a scientific basis for the exploration of paleo-reservoirs in the southern Qiangtang Basin.