Thermal Maturity Indicators Research Articles

Geochemical Characteristics and Significance of Molecular Markers in the Paleogene-Neogene Crude Oils of the Northwest Qaidam Basin.

The western Qaidam Basin is rich in oil and gas resources, constituting over 90% of the total oil and gas resources in the whole basin. However, the regional distribution characteristics of molecular markers of crude oil and the petroleum system elements relevant to the distribution of oil and gas in the northwest Qaidam Basin are still unclear, which restricts further exploration of oil and gas reservoirs. A total of 38 crude oils were collected from the Xiaoliangshan Sag and Mangya Sag in the northwest Qaidam Basin and analyzed by gas chromatography-mass spectrometry (GC-MS). The indicators of sedimentary environment, organic matter source, and thermal maturity show regular changes from the west to the east in the Xiaoliangshan Sag and Mangya Sag. The nC21 -/nC22 +, n(C21 + C22)/n(C28 + C29), and C27-C28-C29 regular sterane distribution characteristics indicate that the input proportion of lower aquatic organisms in source rocks (E3-N1) gradually increases, while the input proportion of terrigenous organic matter gradually decreases. The triaromatic dinosterane index (TDSI) and methyltriaromatic steroid index (MTDSI) indicate that the input proportion of dinoflagellates gradually increases. The gradual increase in the Pr/Ph ratio indicates a decrease in the reducibility of the sedimentary environment of source rocks. The gammacerane index (Ga/C30H) and methylated-2-methyltrimethyltride-cylchromans (MTTCs) indicate that the degree of stratification and salinity of water body gradually decrease. A total of 23 thermal maturity parameters indicate that crude oil is in a mature evolution stage, and the thermal maturity of crude oil increases with depth, indicating that there are the characteristics of hydrocarbon accumulation close to source rocks. The variation features of sedimentary environment, organic matter origin, and thermal maturity indicators from the west to the east in the Xiaoliangshan Sag and Mangya Sag are controlled by the sedimentary structure characteristics of the study area.

Acritarch Palynomorph Darkness Index (PDI) as an indicator of thermal maturity in Silurian sections from Saudi Arabia

Palynomorph Darkness Index (PDI) measurements on acritarchs from Silurian strata in Saudi Arabia exhibit an irregular but potentially useful relationship to other vitrinite reflectance proxies. Four distinct stages in PDI evolution can be recognized with thermal maturity. In Stage 1, acritarch PDI is <10% and shows no increase with increasing maturity. A very rapid increase in PDI towards the end of the oil window from <10% to ca. 25% characterises Stage 2, which is followed by a gradual increase in Stage 3 from ca. 25% to approximately 80%. PDI Stage 4 is represented by postmature rocks, with acritarch PDI >82% and showing little change with increasing maturity. Acritarch fluorescence is totally extinguished within the oil window.

The application of diamondoids indices for oils from Block 4 of the Muglad Basin in the middle of Africa

The abundances and distribution diamondoids were studied with a series of crude oil samples from Block 4 of the Mugald Basin in Sudan, to investigate the validity of various diamondoid parameters on the oil source, thermal maturity and biodegradation information. All crude oils of Block 4 were generated by lacustrine source in lower part of the Abu Gabra Formation as a whole, and can be further divided into two crude oil groups: oil group of the Neem-Azraq Uplift and oil group of K-3 well and B-1 well. They are all mature oils within oil window and four crude oils from the Neem-Azraq Uplift were slightly biodegraded. The concentrations of diamondoids in oils of K-3 well and B-1 well, especially the concentration of diamantanes, are higher than those of oils from the Neem-Azraq Uplift. The concentrations of diamondoids are mainly controlled by source of oil, while the influence of thermal maturity and biodegradation may be limited. The isomerization ratios as indicators of thermal maturity are inapplicable at the mature stage, but DMDI-2, 4,8/3,4-DMD and 1-EA/3-EA can clearly distinguish the two groups of crude oils. The concentration ratios of oils from K-3 and B-1 wells are significantly lower than these of oils from Neem-Azraq Uplift, and these concentration ratios including newly proposed parameters such as MAs/DMAs, DMAs/TMAs, D/MDs, MDs/DMDs and so on, are effective indicators on organofacies and oil group division within oil window.

Comment on: Carbonaceous matter in ∼ 3.5 Ga black bedded barite from the Dresser Formation (Pilbara Craton, Western Australia) – Insights into organic cycling on the juvenile Earth

Weimann et al. (2024) offer important insights into carbonaceous matter (CM) preserved within bedded barite from the 3.48 billion-year-old Dresser Formation (Pilbara Craton). However, issues in the fitting of CM Raman spectra and the application of Raman CM thermometry cast doubts on the conclusion that 'CM in quartz veins yielded much lower temperatures of ∼ 220 °C, suggesting that quartz-vein associated CM entered the barite after 3.3 Ga' (Weimann et al., 2024). A primary concern is the inaccurate fitting of the CM's D1 band, whose spectral position (typically in the c. 1335–1355 cm−1 range) and full width at half maximum (FWHM) are indicators of thermal maturity (Kouketsu et al., 2014). This commentary emphasizes the implications of misfitting D1 and other issues in fitting the broader CM signals between 1100 and 1700 cm−1. Specifically, the omission of D4 (c. 1250 cm−1) resulted in a systematic overestimation of D1-FWHM and, consequently, unreasonably low thermal maturity estimates. We show that a more precise fitting including D4 – recognizing that CM spectra with a thermal maturity below 300 °C generally display a corresponding shoulder at c. 1250 cm−1 – yields much higher thermal maturity estimates that appear to align closely with the peak temperature (c. 290 °C) of the Dresser Formation's 3.3 Ga metamorphic event. This suggests a (near) syngenetic origin for the quartz-vein-hosted CM, challenging the notion of post-metamorphic infiltration. Consequently, these results also question Weimann et al.'s (2024) interpretation that the much higher thermal maturity (c. 350 °C) of a distinct CM generation, situated within the barite crystal’s growth zonations, stems from metamorphic overprinting. Instead, it can be reconciled with the thermal maturation of the CM during its transportation within the ancient Dresser hydrothermal system, prior to its concentration within the barite.

Characterization of the evolution of thermal maturity and pore structure of continental organic-rich shales

To clarify the evolution of thermal maturity and pore structure in continental organic-rich shales, calcareous shales of the Liaohe Basin (China) were pyrolyzed, and examined using Raman spectroscopy, Fourier transform infrared spectroscopy (FTIR), X-ray diffraction (XRD), X-ray photoelectron spectroscopy (XPS), scanning electron microscopy (SEM), nitrogen sorption isotherms, and nuclear magnetic resonance (NMR) spectroscopy. The increase in Raman G‒D band separation and decrease in Raman ID/IG ratio with increasing thermal maturity indicate that these parameters provide superior thermal maturity indicators. This is also confirmed by the good linear correlation of G‒D band shifts and ID/IG with vitrinite reflectance (VR) and maximum temperature (Tmax), respectively. The relative detection accuracy (DA), sampling requirements (SR), sample preparation (SP), detection time (DT), and equipment requirement (ER) of VR, G‒D band shifts, ID/IG, Tmax, FTIR, and XPS indicate that Raman analysis is a simple, quick, and robust method to evaluate thermal maturity. The moderate SR, complex SP, and long DT suggest that VR and Tmax are less widely applicable for characterizing thermal maturity. The FTIR and XPS techniques provide semi-quantitative maturity indicators with poor DA and high ER. Pores observed within organic matter and minerals under SEM indicate that an increase in thermal maturity not only affects the development of organic pores but is also beneficial for the formation of mineral dissolution pores, such as those formed during the transformation of Na0.95Ca0.16Al1.16Si2.84O8 to Na0.84Ca0.02Al1.02Si2.98O8, a process confirmed by XRD. The BET and NMR data also indicate that the development of pore structure is closely related to the evolution of thermal maturity in calcareous shale. During the initial stage, primary pores are filled by bitumen generated from kerogen; this leads to a decrease in transition pores, mesopores, and shale porosity, and reduced pore connectivity. Then, secondary nanoscale pores, transition pores, and mesopores increase with increasing thermal maturity. The peak in secondary porosity is consistent with the liquid hydrocarbon production rate peak, a process that increases shale porosity and leads to improved pore connectivity. The dissolution of minerals induced by organic acids may also contribute to this secondary porosity. With a further increase in thermal maturity, secondary porosity at the microscale is further developed, while transition pores and mesopores collapse, resulting in reduced pore connectivity. The poor pore connectivity that occurs at both low and high VR values may be more conducive to the preservation of shale oil and gas. This study is significant for research into the evolution of thermal maturity and pore structure in continental organic-rich shales.

The organic geochemistry of crude oil in the Saltpond Basin (Ghana): Organic source input, depositional environment, and thermal maturity

The Saltpond Basin, situated within the South Atlantic margin of Ghana, is a significant area for petroleum exploration but has received relatively limited research attention. Previous studies have examined source rock composition, but data on crude oil organic chemistry are lacking, hindering understanding of the basin’s petroleum system and evolution. To address this gap, we analyzed biomarkers and stable carbon-isotope ratios in Saltpond Basin crude oil using gas chromatography–mass spectrometry and gas chromatography–isotope ratio mass spectrometry to elucidate organic matter source, depositional environment, and thermal maturity. Findings were compared with oils from the West African segment of the South Atlantic margin, namely the Tano Basin and the Niger Delta Basin, to identify potential correlations and gain insights into regional variations. Molecular and isotopic results unveiled a significant prevalence of organic matter derived from lower marine organisms. Patterns of organic matter deposition and preservation in Saltpond oil samples suggested a suboxic marine transitional environment, contradicting conventional understanding of terrestrial dominance in such settings. Moreover, the potential for degradation processes to obscure differentiation between terrestrial and marine organic matter origins underscores the complex nature of organic matter dynamics in transitional marine environments. Analysis of molecular thermal maturity indices suggested Saltpond oils were expelled from source rocks exhibiting thermal maturity at the early maturity stage. Correlation analysis unveiled genetic disparities among crude oils sourced from the Saltpond Basin and those from the Tano and Niger Delta Basin, primarily due to variations in source input and depositional environment conditions. Saltpond oil exhibits lower terrestrial organic input than Tano Basin’s crude oils, which also have less terrestrial input than Niger Delta Basin crude oils. Additionally, its paleodepositional environment notably differs from oils in the Tano Basin (anoxic transitional marine-lacustrine settings) and the Niger Delta Basin (suboxic–oxic terrigenous deltaic or marine or lacustrine environments). Thermal maturity range of Saltpond oil is comparable to oils in the Tano Basin but lower than oils in the Niger Delta Basin. These findings provide valuable insights into petroleum generation history and unique organic geochemical characteristics within the Saltpond Basin, essential for exploration, production, and environmental management efforts in the region. Furthermore, correlation studies provide evidence that distinct biological, geological, and paleoenvironmental conditions shaped various oil types in the West African segment of the South Atlantic margin.

Solid bitumen as an indicator of petroleum migration, thermal maturity, and contact metamorphism: A case study in the Barrandian Basin (Silurian - Devonian), Czech Republic

Silurian and Devonian marine shales and limestones of the Barrandian Basin host abundant black solid, non-fluorescing bitumens that fill tectonic fractures and veins, and occlude fossil moulds and diagenetic concretions. Solid bitumen, interpreted as thermally degraded petroleum, entered the rocks during several successive episodes of fracture-bound petroleum migration that occurred during deeper burial of the strata. Regional distribution of bitumen reflectance values that range between ∼0.9–2.3% Rr, correlate with variations of its FT-IR and Raman spectroscopic characteristics and aromatic hydrocarbon composition, and collectively evidence the maturity trend increasing across the basin from the southwest to the northeast. The reflectance of chitinozoans and graptolites (∼0.8–1.9% Rr) in the country rocks and homogenization temperatures of hydrocarbon fluid inclusions document palaeotemperatures ranging between ∼90–150 °C, characteristic of the oil window zone grading into the gas/condensate zone. Although in a basin-wide perspective the averaged values of solid bitumen and zooclast optical reflectance converge and indicate the same northeastern-increasing regional diagenetic trend, solid bitumen reflectance values vary considerably at individual localities and even within some bitumen samples. The wide scatter of optical reflectance values and the heterogeneity of optical properties, which were attributed to the presence of multiple source rocks in the basin, the variable lithology of bitumen host rocks, or other variables, hamper the use of solid bitumen as a simple alternative to zooclast/vitrinite reflectance palaeothermometers in a given basin. On the other hand, the highly anisotropic domain and the mesophase “coking” textures of the solid bitumen that were recognized in the NE part of the basin provide unique evidence on an anomalous, hitherto unrecognized, geologically short-lasting thermal event that affected the Palaeozoic rocks. A line of indirect evidence suggests that the coking of the bitumen was caused by a cryptic intrusion, possibly a concealed branch of the Central Bohemian Pluton, which intruded into the strata during the Variscan orogeny. More rarely occurring semi-solid, vividly yellow fluorescing waxy bitumen, that postdates solid bitumen in some fractures and voids, does not reveal a regional thermal maturation trend. It precipitated from relict waxy oils that migrated through the strata during a post-Neogene uplift of the Barrandian region.

Impact of aerobic reworking of biomass on steroid and hopanoid biomarker parameters recording ecological conditions and thermal maturity

Steranes and hopanes are the biomarkers of eukaryotic sterols and bacterial hopanols. Extracted from sedimentary rock, they are widely used to assess burial temperatures and palaeoecological conditions. The relative proportion of steranes and hopanes is commonly applied as a measure of the flux of eukaryotic versus bacterial biomass into sediments, and the relative abundances of C27, C28 and C29 steranes are proxies for shifts in eukaryote ecology. In Recent sediments, intact sterols provide additional information about particular eukaryotic origins. However, biological lipid distributions are not always recorded faithfully in sediments. Based on observations on modern algae and plants, and on 558 million year old fossil macroalgae from the Ediacaran of the White Sea, we suggest that these biomarker proxies can be severely altered by aerobic microbial reworking, to the extent that a complete loss of primary ecological information may occur. Network analysis on the biomarker data suggests that oxic degradation also affects isomer and homolog distributions of saturated and aromatic steroids, hopanes, cheilanthanes and n-alkanes, generating anomalies in apparent thermal maturity indicators and other proxies. In our dataset, between Ediacaran macroalgae that experienced the least and the most oxic degradation, the absolute concentration of biomarkers decreases 80-fold, and at the same time the proportion of steranes over hopanes decreases by a factor of 82, while the proportion of C29 steranes among total steranes decreases from 91% to 47%. Such redox dependent offsets may explain the recurrently erratic behaviour of numerous biomarker parameters. While these results impart constraints on the interpretation of biomarker distributions, they do provide a tool for evaluating the effects of oxygen exposure and microbial degradation on organic matter preservation in recent and ancient environments and may point towards a solution for the correction of such effects.

Organic petrography and geochemistry of the Fu 2 member of the Paleocene Funing formation, Gaoyou Depression, Subei Basin, Eastern China: Implications for shale oil potential

The Fu 2 Member of the Paleocene Funing Formation in the Gaoyou Depression, Subei Basin is an organic matter-rich formation, and has a high potential for shale oil exploration and exploitation. Total organic carbon (TOC), organic petrography, Rock-Eval pyrolysis, chloroform bitumen “A” extraction, and SARA (saturates/aromatics/resins/asphaltenes) composition analyses of shale samples from one drill core in the studied area spanning a thickness of 257 m were conducted to study the organic matter (OM) richness, kerogen type, maceral composition, hydrocarbon generation potential, and oil content of the Fu 2 Member. Results show that the Fu 2 Member shales in the study area have a Ro of 0.87%, in the peak oil window, suggesting a high potential for hydrocarbon generation. The studied OM in shales mainly belongs to kerogen Type II, with a minor portion of Type I and Type III. Under microscopic observation, macerals in the studied shales are mainly composed of vitrinite, inertinite, alginite, and solid bitumen. The studied shales have an average TOC content of 1.41 wt%, indicating good petroleum potential. The variations of maceral compositions could affect the reliability when the Tmax is used as an indicator of thermal maturity. The lower Shale 4 and upper Shale 5 interval (3650–3700 m), with high TOC and high oil saturation index, is identified as the sweet-spot interval of the Fu 2 Member for shale oil exploration.

Evaluation of portable Raman spectroscopic analysis for source-rock thermal maturity assessments on bulk crushed rock

This study presents a simplified method and empirical relationships for determining organic matter thermal maturity using a portable Raman system equipped with a 785 nm laser, for analysis of crushed, whole-rock samples. Suites of rocks represented by shale and coal samples with various mineralogical composition, thermal maturity, and total organic carbon (TOC) were used to test the method and build correlations between Raman band separation (RBS) values and traditional thermal maturity indicators, organic matter reflectance (Ro), and programmed temperature pyrolysis (Tmax) values. A set of disparate shale samples, where both vitrinite and solid bitumen reflectance values were reported, have Ro values that range from 0.40 to 4.62%. Above 3.35% Ro, the corresponding RBS values plateau at ∼290 cm−1, thus correlations were evaluated with a linear regression (R2 = 0.96) between 0.40 and 3.35% Ro. Shale samples with Ro < 2% and Tmax < 551 were also used to correlate Tmax and RBS, yielding a linear correlation with an R2 of 0.94. For the coal data set, Ro values range from 1.21 to 4.08% and correlated RBS values plateau at ∼250 cm−1 above Ro = 3.0%, suggesting its correlative application below this maturity level. Several sample preparation methods were tested on cuttings material and standard deviation values for RBS were minimized by washing, drying, and hand crushing the material to pass through a 40-mesh sieve, although less preparation can still yield reliable results. The high degrees of correlation between whole-rock RBS data and two thermal maturity indicators demonstrate the utility of this approach for generating source rock thermal maturity data from minimally processed, whole-rock samples which could easily be applied in field or laboratory settings.

The effect of lamina and lithofacies assemblage on molecular maturity of oil in a shale source-rock reservoir

This paper discusses the effect of the source rock–reservoir assemblage and the assemblage–induced variability in hydrocarbon expulsion and the subsequent molecular composition as well as molecular thermal maturity within a hybrid shale system. The characterization work was conducted on lithofacies and microlamina scales using core samples from the Chang 73 sub-member of the Triassic Yanchang Formation in the Ordos Basin, China. Samples were collected from a narrow interval with a depth range of less than 15 m, and the main characterization work was performed by Rock-Eval pyrolysis and GC–MS analysis. The results show that chemical fractionation of preferential expulsion and migration of the saturated fraction exists in the source rock–reservoir assemblages at both the lithofacies and lamina scales. However, the molecular composition behaves differently at the lithofacies and lamina scale's source rock–reservoir assemblages, in which ∑C21−/∑C22+ is higher in lamina scale reservoir but lower in lithofacies scale reservoir. It is assumed that the low-molecular weight n-alkanes also follow molecular fractionation. The lithofacies reservoir has a lower ∑C21−/∑C22+ because of the strong storage capacity of the laminated micro-reservoir within shale, which prevents the newly generated lighter oil from being charged into the lithofacies reservoir. The variation trends of thermal maturity indices Ts/hopane, the relative pregnane content, and TA(I)/TA(I + II) ratios, which have the same chemical basis with ∑C21−/∑C22+, carry the same maturity signature as ∑C21−/∑C22+. The above profile of the molecular composition and molecular-derived thermal maturity parameters indicate that within the short interval of a shale system where no differences in thermal maturity are expected, chain scission reactions and their derived thermal maturity indicators are very sensitive to source rock and reservoir. In addition, within a shale system, oil is more easily to expel out from the organic-rich lithofacies that are interbedded with organic-lean lithofacies. Oil expulsion may promote both chain cracking of oil and subsequently kerogen decomposition. This may provide geological evidence to explain why the frequent-stacking assemblage of source rock and reservoir lithofacies in a hybrid shale system is an ideal target for shale oil exploration.

Organic matter accumulation and hydrothermal effect of the Barney Creek formation in the Glyde Sub-basin, northern Australia

The Glyde Sub-basin is a large petroliferous unit in the McArthur Basin, northern Australia, and it is situated ∼100 km southeast to the world-class McArthur River Zn–Pb hydrothermal deposit. The Paleoproterozoic Barney Creek Formation (BCF) is the hydrocarbon source rock in the sub-basin, and also the host rock for the McArthur River deposit. The controlling factors of organic matter accumulation and the hydrothermal effects on organic matter thermal maturity are not well-constrained for the BCF in the Glyde Sub-basin, hindering petroleum and mineral explorations. To address these issues, rock eval pyrolysis, reflectance measurement, trace element analysis, Nd–Hf and Re–Os isotopic analysis were conducted for the BCF samples taken from the drill-hole GRNT-79-5 in the Glyde Sub-basin. Analysis of trace elements and Nd–Hf isotopic ratios shows that cuttings of the BCF were derived from a mafic-dominant source (La/Ni = 0.89–2.27, La/Cr = 0.63–1.04, La/Sc = 3.16–4.95, La/V = 0.23–0.81, ϵNd = −5.01 to −2.98, ϵHf = −2.27 – 1.8), which may have contributed to a pronounced phosphorous delivery to the basin, resulting in enhanced primary productivity of seawater. Therefore, the high organic matter abundance in the BCF (TOC = 0.86%–5.04%) is most likely controlled by the primary productivity of seawater. The 187Re/188Os ratios (34.954–432.95) of a suite of samples negatively correlate with proportions of kerogen in organic matter (0%–94%), suggesting that burial temperature has reset the Re–Os isotope system. Hydrocarbon generation may have been promoted by hydrothermal fluid flows which relate to the McArthur River mineralization because the Re–Os isotope data yield an isochron age similar to the age of mineralization. The Re–Os isotope data provide direct evidence that the BCF in the Glyde Sub-basin was affected by hydrothermal fluids. However, the co-variation between thermal maturity indicators (Tmax = 436–444 °C; reflectance of solid bitumen = 0.34%–0.66%) and burial depth (97–512 m) suggests that organic matter thermal maturation primarily resulted from burial diagenesis rather than hydrothermal fluid flows. This indicates that temperatures of hydrothermal fluids was not high enough to significantly alter the thermal regime of the studied region.

Comparison of optical and geochemical thermal maturity parameters over a stratigraphically controlled natural transect

Thermal maturity is a fundamental parameter in understanding organic matter evolution during the burial of sedimentary rocks. To this end, numerous optical and geochemical thermal maturity parameters have been proposed, most commonly applied are reflectance or programmed pyrolysis Tmax. Reflectance of vitrinite macerals, or increasingly commonly of solid bitumen macerals, is the classical and well-standardized technique in thermal maturity studies. However, this technique can be influenced by operator bias in acquisition and interpretation. The low cost and wide availability of programmed pyrolysis data has led to the adoption of Tmax as a primary thermal maturity proxy, particularly in industrial studies. However, programmed pyrolysis was originally conceived as a screening tool and significant inconsistencies of Tmax with thermal maturation have been reported.Detailed comparison of maturity proxies is often hampered by the availability of suitable sets of samples from a maturity gradient along uniform facies. Since many of these proxies are influenced by formation specific parameters, the most valuable comparisons must be made using stratigraphically and lithologically controlled sample sets, which are relatively rare. This work examines a natural thermal maturity transect, integrating multiple methodologies to give a detailed discussion of the applicability of optical and geochemically based thermal maturity indicators in the immature to early generation range. This study utilizes a stratigraphically constrained sample set of Upper Cretaceous strata in western Canada taken from 10 wells ranging in thermal maturity from approximately 0.2 to 0.8 %VRo and is based on application of three independent methodological approaches: reflectance measurements, Tmax, and hopanoid and steroid based molecular maturity ratios.Data and correlation equations between major thermal maturity indicators demonstrates solid bitumen reflectance at pre-oil window maturity levels lies along a continuum. Reporting values within somewhat inconsistent classification schemes of bituminite and solid bitumen maceral, as suggested in some recent studies, diminishes the applicability and usefulness of this parameter. Comparison of microscopy and pyrolysis-based maturity proxies with the diagenetic evolution of hopanoids and steroids revealed a robust covariance. Individual molecular maturity parameters are unsuitable to cover the full range of thermal maturity but the wide array of proxies applicable in narrower maturity ranges allows for an optimized selection of those parameters within a given maturity interval. Pyrolysis-derived Tmax and optical determination of OM properties are effective covering a wide range of conditions ranging from the eogenetic to catagenetic stages. Fluorescence analysis is most robust in the eogenetic to diagenetic stages, whereas reflectance measurements provide higher confidence levels at elevated diagenetic or catagenetic stages. Given the limitations of individual thermal maturity parameters, thermal maturity investigations following an integrative, multi-disciplinary approach will limit the impact of uncertainty from any one parameter, improving the odds of achieving a more reliable maturity assessment.

Formation of pyrobitumen from different types of crude oils and its significance: Insight from elemental composition analysis

Pyrobitumen, considered a carbon-rich solid product of oil thermal cracking, widely exists in oil/gas source rocks and reservoirs. The importance of the polar fractions on the formation of pyrobitumen has been acknowledged. However, the precise role of the polar fractions in the formation of pyrobitumen is still not well understood. Since the heteroatoms of nitrogen (N), oxygen (O) and sulfur (S) mainly exist in the polar fractions, the investigation of their content and evolution characteristics during the formation of pyrobitumen will provide an understanding of the formation mechanism of pyrobitumen. In this study, laboratory pyrolysis experiments on three types of oil (normal oil, light oil and heavy oil) were conducted. The major pyrolysis products, such as gaseous compounds, liquid fractions and pyrobitumen, were quantitatively analyzed. The elemental compositions of carbon (C), hydrogen (H), O, N and S in the obtained liquid products and pyrobitumen were measured. From the yields of the pyrolysis products and the determined elemental compositions, we propose a three-stage formation scheme for pyrobitumen. In the first stage, the reactions are dominated by a cross-linkage of the polar fractions in crude oil that occurs at an Easy Ro>1.0% (H/C for pyrobitumen < ca. 0.8–1.0). In the second stage, the cross-linking reactions will occur with both the hydrocarbons (saturated and aromatic fractions) and polar fractions with an Easy Ro > 1.4–1.6% (H/C for pyrobitumen < ca. 0.6–0.7). In the third stage, almost all removable components in the crude oil are transformed into solid bitumen and CH4 at an Easy Ro>3.0% (H/C for pyrobitumen < ca. 0.4). This scheme is expected to be applied in studies to distinguish the original types of oil for pyrobitumen and establish a new thermal maturity index based on pyrobitumen and oil/gas resource assessment.

Maceral Control on the Hydrocarbon Generation Potential of Lacustrine Shales: A Case Study of the Chang 7 Member of the Triassic Yanchang Formation, Ordos Basin, North China

Organic matter (OM) type critically controls the hydrocarbon generation potential and organic pore development in black shales. However, maceral variation in lacustrine shales and its control on hydrocarbon generation potential and organic pore development are not yet well understood. In this study, 15 Chang 7 Member shale samples of the Yanchang Formation, Ordos Basin, were investigated with organic petrography, Rock-Eval pyrolysis, and a scanning electron microscope to study the maceral composition, hydrocarbon generation potential, and organic pores in this black shale succession. The results show that the studied shales are in the oil window (Ro~0.70%). OM belongs to Type I and Type III kerogen, as demonstrated by Rock-Eval pyrolysis. Macerals in the Chang 7 Member shales are composed of amorphous OM, alginite, sporinite, liptodetrinite, vitrinite, inertinite, and solid bitumen. Amorphous OM and alginite are major hydrocarbon-generating macerals, and their content determines the hydrocarbon potential of shales. Secondary organic pores were not observed in the studied Chang 7 Member shales due to either a low thermal maturity or a dominance of terrigenous OM. Maceral variation can affect the reliability of using Rock-Eval Tmax as a thermal maturity indicator. This study provides important insights into maceral control on hydrocarbon generation and organic pore development in black shales, calling for a critical evaluation of OM in black shale successions with organic petrography.

Identification, distribution and geochemical significance of phenyldibenzofurans in coals

Four phenyldibenzofuran (PhDBF) isomers were unambiguously identified for the first time in coals through co-injection of commercially available standards. PhDBF isomers were detected in all coals from the East China Sea Shelf and the Ordos basins. The stability order of PhDBFs was confirmed to be 4-PhDBF > 2-PhDBF > 3-PhDBF > 1-PhDBF. The degree of molecular structural deformation of PhDBFs was also determined. The influence of thermal maturity on the distributions of PhDBFs in sedimentary organic matter containing Type II–III kerogen was systematically investigated, and the concentration of 4-PhDBF relative to 2-PhDBF and 3-PhDBF was found to be influenced by thermal maturation. The previously proposed maturity indices based on PhDBF ratios (PhFR-1 and PhFR-2) were found to be useful in coal facies with high thermal maturity (≥ 1.0 %Ro) on the basis of density functional theory (DFT) calculations and geochemical data. Two calibrations of PhFR-1 and PhFR-2 against the measured vitrinite reflectance (%Ro) were established, which are as follows: %Rc = 3.0 × PhFR-1/100 + 1.0 (≥ 1.0 %Ro) (R2 = 0.95) and %Rc = 7.0 × PhFR-2/100 + 1.0 (≥ 1.0 %Ro) (R2 = 0.96). PhFR-1 and PhFR-2 have good correlations with the other widely used thermal maturity indicators. The oxic sedimentary environment is likely more beneficial to the generation of phenyldibenzofurans and methyldibenzofurans. PhDBFs in coals may be formed during diagenesis or early catagenesis and intermediates in the producing of more condensed aromatic compounds from high thermal maturity. The results of this study provide a deeper insight into the occurrence, distribution and significance of PhDBFs in sedimentary deposits.

The diagenetic continuum of steroid hydrocarbon transformation from early diagenesis into the oil window

Steroids and their derivatives are ubiquitous in the sedimentary rock record, where they are widely applied as biological or geochemical markers to determine organic facies as well as thermal maturation of bitumen and oils covering the diagenetic to catagenetic stages. The diagenetic continuum from early diagenesis into catagenesis of steroids has not been extensively studied despite the importance of these reactions in influencing the successive continuum of late diagenetic transformations.This study utilizes a stratigraphically constrained transect of 9 wells from the Upper Cretaceous Second White Specks and Belle Fourche formations of south-central Alberta, Canada ranging in thermal maturity from 0.2 %VRE to 0.8 %VRE. Biomarkers were examined from 69 samples from 8 wells and thermal maturity was determined from 87 samples from 9 wells using HAWK programmed pyrolysis analysis. Relative and absolute abundances of regular sterane, diasterene, diasterane, monoaromatic steroid, and triaromatic steroid biomarkers and changes in the proportions of steroid compound classes were determined and evaluated for thermal maturity. Additionally, isomerization ratios within each of the compound classes were examined with increasing thermal maturation.Rearranged diasterenes initially dominate the steroidal hydrocarbons, followed by diasteranes in the late diagenetic and catagenetic stages and at peak oil maturity (0.8 %VRE) diasteranes were most abundant. The relative abundance of a steroid is initially controlled by its rate of production or isomerization from a biological precursor, but at higher thermal maturities selective catagenetic destruction alters the relative abundance of steroid classes, with aromatic steroids and regular steranes being degraded or expelled earliest. Thermal maturity parameters based on the isomerization of regular steranes, and the aromatization of monoaromatic steroids are effective thermal maturity indicators in specific but overlapping ranges beginning at 0.2 %VRE. This work represents a novel examination of a natural thermal maturity transect and helps to consolidate our understanding and application of the diagenetic transformations of steroid compounds.

Biomarkers, light hydrocarbons, and diamondoids of petroleum in deep reservoirs of the southeast Tabei Uplift, Tarim Basin: Implication for its origin, alteration, and charging direction

The Atan Bulge in the southwestern Tabei Uplift of the Tarim Basin provides insights into the geochemistry of the oils and condensates in deep Ordovician reservoirs because its reservoir burial depth is generally greater than 6000 m. To investigate the oil origin, alteration, and migration pathways, the carbon isotopes, biomarkers, light hydrocarbons, and diamondoids of 16 oil and condensate samples from the Ordovician reservoirs in the Atan Bulge were analyzed. The results show that chain alkanes dominate the light hydrocarbons, followed by cycloalkanes and aromatic hydrocarbons. 1-methyladamantane (MA) dominates the diamondoids, followed by 1,3-dimethyldiamantane (DMD). The samples lacked biodegradation and thermochemical sulfate reduction signatures. Except for a few samples near the Manjiaer Depression, the evaporative fractionation caused by late natural gas charging is generally weak. The oil geochemistry suggests that the oils and condensates are primarily derived from lower Cambrian marine shale, and the organic matter is mainly type II. The equivalent vitrinite reflectance (Rc) calculated using thermal maturity indicators derived from methylphenanthrene, methyldiamantanes, and C5–C7 light hydrocarbons, respectively, is in the ranges of 0.78%–1.04%, 1.1%–1.5%, and 1.06%–1.48%. The samples' low (3-+4-)-methyldiamantane concentrations (36–76 μg/g) imply a low level of oil cracking. The carbon isotope distribution among oil fractions and different maturity ranges suggest that crude oil was generated and charged multiple times. The maturity of the samples decreases from SSE to NNE, indicating that the petroleum likely migrated from strike-slip faults during its primary charging period, with the Manjiaer Depression and its slope serving as the primary source kitchens.

Hydrocarbon prospectivity of the southern Bida and northern Anambra basins, Nigeria using palynological and geochemical studies

• Hydrocarbon prospectivity and depositional environments of two basins. • Integrating palynological and geochemical data in evaluating hydrocarbon potential. • Identifying the depositional environments of the basins. The palynological and geochemical analyses were carried out on shales samples in borehole and outcrop sections of the southern Bida and northern Anambra basins respectively. These analyses aimed at evaluating the hydrocarbon prospectivity of the basins. The results of total organic carbon (TOC) of 0.30–9.01 wt% in Patti Shale interval of Agbaja section in southern Bida Basin revealed a high TOC, depicting a substantial organic matter in the source rock. TOC of 0.82–2.56 wt% for Patti Shale in Ahoko outcrops (southern Bida Basin) show relatively moderate TOC which revealed a fair organic matter in the source beds. TOC of 0.44–0.95 wt% of Mamu Shales in Ojodu outcrops in northern Anambra Basin indicates a moderate to poor TOC which suggests fair to poor organic matter in the source rock. Hydrogen Index (HI) range of 45- 153 mgHC/grock with producible hydrocarbon (S 2 ) of 2.60–5.00 mgHC/grock reveals very good source rock potentials in the Agbaja section. HI of 0.08–0.57 mgHC/grock, S 2 of 0.12 mgHC/grock in Ahoko and HI of Mamu Shales of 30–136 mgHC/grock, S 2 of 0.14–0.90 mgHC/grock in Ojodu outcrop, both revealed poor to fair source rock potentials. The results of vitrinite reflectance (Ro) and maximum temperature (T max ) range (0.30 to 0.55% and 420 to 435 °C, respectively) suggest a low to relatively high thermal maturity index in both frontier basins. The thermal maturity of the shales in Agbaja borehole sections is moderate to high, although from record no petroleum has been produced from the sections in the basin. From the organic matter type, the kerogen is classified as type II/III and IV for both basins. The palynological results propose the Maastrichtian age for both basins, regarding the rich accumulation concerning micro-florals; Psilatricolporites prolatus, Florentinia laciniata seghiris, Echitriporite trianguliformis, Arecipites sp. Monoporite, Triporites . Dinocysts belonging to the Spiniferites, and Deflandreacean dinoflagellate, and Acritaarchs of Polipodiaceosporite retigularis, Acripite sp., which were analyzed from the shale intervals in the basins; suggest a Cretaceous age, marginal marine-continental environments, paleovegetation, and humid climate. Finally, the palynological, and geochemical analysis results will contribute knowledge that will be useful for hydrocarbons exploration in these frontier basins in Nigeria.

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.