Clay minerals exert critical controls on organic matter transformation and hydrocarbon generation through adsorption and catalysis. Yet, quantifying their catalytic effects remains challenging due to mineralogical diversity and microstructural complexity, especially for mixed-layer clay minerals that are widespread in natural sedimentary environments. To address this issue, mixed-layer illite-smectite clays (MLIS) with different layer ratios (0%, 50%, 70%, and 100% illite) were used to examine their catalytic effect on the pyrolysis of 12-aminododecanoic acid (ALA). ALA is a model compound representing aliphatic chains and carboxyl/amino groups common in natural organic matter (OM). Pyrolysis experiments were conducted at 350 degrees C and 36 MPa. MLIS50% (with 50% illite layers) exhibited exceptional catalytic activity, significantly enhancing the yields of C1-C5 hydrocarbons and CO2 compared to pure ALA and other MLIS variants. This high activity arises from the R1 ordered structure, which enables: (i) charge transfer from high-charge illite layers that stabilizes Br & Oslash;nsted acid sites in adjacent smectite interlayers; (ii) nanoscale proximity of Br & Oslash;nsted and Lewis acid sites for cooperative catalysis; and (iii) ink-bottle-shaped pores that confine ALA molecules, prolonging intermediate residence time for sequential decarboxylation and C-C bond cleavage. In contrast, MLIS-0% undergoes acid site deactivation induced by excess interlayer water; MLIS-70% displays spatial separation of B/L sites due to K+-dominated interlayer collapse; and MLIS-100% contains almost no accessible acid sites. A 50% smectite layer composition corresponds to the R0-to-R1 ordering transition in natural illitization, a diagenetic stage coinciding with peak oil generation. This suggests its potential as a tentative mineral indicator for high-quality hydrocarbon generation in sedimentary basins, while further validation using natural geological samples is still required. This study provides systematic structure-activity insights into the role of clay catalysts in hydrocarbon formation during sedimentation and diagenesis.

Unconventional shale resources remain crucial to energy security. In situ conversion technology (ICP) offers a promising pathway for exploiting low-maturity shale, yet the distinct roles of kerogen and bitumen during thermal conversion are not fully understood. This study investigates the decomposition behavior of kerogen and extracted bitumen from the Shahejie Formation through gold-tube pyrolysis experiments at 50 MPa and heating rates of 2 degrees C/h and 20 degrees C/h. The results show that the yield curves of C1, C2-C5, and C6-C14 generated from kerogen and bitumen exhibited similar trends. In contrast to the C15+ fraction from kerogen, which initially increased and then decreased, the yield of C15+ from bitumen began to decline from the onset of cracking. Additionally, the CO2 generated from the kerogen continued to increase until the end of pyrolysis, whereas the CO2 from the bitumen reached its maximum at an EasyRo of approximately 1.8%. The kinetic results show that bitumen has a higher activation energy for gas generation than kerogen, while kerogen has a higher activation energy for oil generation than bitumen. A heating program of 1 degrees C/day rate, 324 d duration, and a final temperature of 360 degrees C was applied to predict oil and gas generation during ICP. Below 326 degrees C, the proportion of C1 and C2-C5 contributed by kerogen increased and exceeded 90%. Although kerogen's contribution ratio of C6-C14 exhibited fluctuating variation characteristics, it remained above 50% across most of the intervals. The gas-to-oil ratio increased rapidly above 299 degrees C and reached 375 m3/m3 by the end of heating.

The coupling of hydrocarbon (HC) generation and expulsion remains a kinetic challenge in petroleum systems. To calculate expulsion kinetics that simultaneously account for HC generation kinetics and the influence of the mineral matrix during release from source rocks, systematic pyrolysis experiments were conducted using the newly developed dual-pressure (lithostatic and fluid pressure) pyrolysis apparatus. The results show that cumulative expulsion curves of C-1, C-2-C-5, C-5-C-14 and C15+ exhibit Boltzmann-type growth trends similar to those of the corresponding generation curves as %EasyRo increases. In addition, at the same pyrolysis temperature, expulsion yields are higher under slow heating rates than under fast heating rates. Therefore, the expulsion kinetics were calculated following the commonly used approach used for generation kinetics. The activation energies for expulsion of the lumped chemical species show a trend opposite to that observed for generation: E-a(C15+) > E-a(C-5-C-14) > E-a(C-2-C-5) > E-a(C-1). This pattern indicates that physical transport becomes increasingly dominant for heavier components, imposing an additional energy barrier beyond that required for generation. The parameters incorporate both the energy barriers for HC generation and those required to transport HCs from the point of their generation to the point of expulsion into another media. As an initial attempt, this model shows promise for application in the In situ Conversion Process (ICP) of oil shale, given the close similarity between our experimental conditions and the operational processes of ICP, but its application to natural petroleum systems remains fundamentally limited due to the oversimplified expulsion dynamics in the current setup.

Gas derived from the primary cracking of kerogen and the secondary cracking of oil has historically been the focus of petroleum geologists, given its importance as a gas source. The Wenchang A Depression within the Zhu III Sub-basin is the largest gaseous hydrocarbon-rich depression in the Pearl River Mouth Basin (PRMB), and the sources of gaseous hydrocarbons in this depression are a research focus. Mud-stones from the Eocene Wenchang Formation contain type I and type II organic matter and are oil-prone, with TOC, S1+S2, and HI values mostly ranging from 1.42% to 3.12%, 9.71 mg/g to 20.61 mg/g, and 410.71 mg/g TOC to 736.17 mg/g TOC, respectively. Data of gaseous hydrocarbon yields and carbon isotopic compositions show that the gaseous hydrocarbons generated from oil-prone mudstones are mainly derived from the secondary cracking of oil, and the plot of delta 13C2-delta 13C3 versus ln(C2/C3) effectively identified the gas source. To further assess the gas generation processes and the ratio of oil-cracking gas under geological conditions, we reconstructed the history of gaseous hydrocarbon generation in mudstones from the Wenchang Formation in the Wenchang A Depression. Results showed that gaseous hydrocarbon generation began at approximately 33 Ma, a maximum of 69% of total gaseous hydrocarbons (C1-C5) was generated by oil cracking, and total heavy hydrocarbon gases (C2-C5) were mainly generated from oil cracking (65%-81%). This study provides a deeper understanding of the characteristics of gas generated from oil-prone mudstones and is important for gas exploration in the Wenchang Depression. (c) 2025 The Authors. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

Thiadiamondoids (TDs) have recently attracted increasing attention as molecular proxies for thermochemical sulfate reduction (TSR) reactions in reservoirs. However, their formation mechanisms, as well as the generation and evolution processes, remain poorly understood. In this study, simulation experiments with a duration of 160 h were conducted on the model compound 1,3-dimethyladamantane (1,3DMA) using the CaSO4, MgSO4, and elemental S systems, with measurements at the 10th, 20th, 40th, 80th and 160th hours during the simulation process being presented. The results indicate that at the end of simulation, the MgSO4 system exhibited the lowest residual amounts of 1,3-DMA, suggesting the highest degree of TSR. Four types of non-hydrocarbon compounds with adamantane structures were detected in the liquid products in the three experiment systems: adamantanones, adamantanols, adamantanethiols (ATs), and thiaadamantanes (TAs). Among these, adamantanones exhibited the highest concentrations in the three simulation systems. In addition, TAs were dominated by C3-TAs in the CaSO4 and MgSO4 systems and by C2-TAs in the elemental S system. The simulation experiments revealed a strong correlation between the concentrations of TAs and adamantanones, suggesting that adamantanones might be the intermediates for TAs. Combined with the synthesis mechanism of TAs from thiaadamamantane-4,8-dione, TDs might have two different genetic mechanisms: (a) low temperature cationic carbon ion rearrangement from diagenesis to early catagenesis stage, and (b) a free sulfur radical mechanism in high-temperature TSR process during middle-late catagenesis. TAs exhibited different generation and evolution processes across different experiment systems. Notably, the MgSO4 system revealed that TAs undergo generation, accumulation, and destruction process, corresponding to Easy%Ro values of 0.89 %-0.98 %, 0.98 %-1.21 %, and >1.21 %, respectively. Among these three simulation systems, dibenzothiophenes (DBTs) concentrations consistently trended upwards, indicating TAs have lower thermal stability than DBTs. (c) 2025 Petroleum Exploration and Production Research Institute Corporation, SINOPEC. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

Improvement in thermal simulation technology will increases the accuracy of predictive geochemistry. A dual- pressure pyrolysis apparatus was developed, to precisely control the fluid pressure and lithostatic pressure during simulated source rock maturation. Two series of pyrolysis experiments were carried out, simulating the same generation process but different expulsion fluid pressure condition. Episodic hydrocarbon expulsion from source rocks under controlled lithostatic pressure and fluid pressure was for the first time observed through thermal simulation experiments. The results were applied to (1) hydrocarbon expulsion efficiency (HEE) analysis, and (2) compositional analysis of oil and gas expelled under different pressures. Results show that HEE is strongly influenced by both fluid and lithostatic pressures. If the oil discharged during depressurization and normal pressure is taken into account, the calculated HEE was 2-31 times the HEE that only considers the high fluid pressure expelled oil. Compared with previous experimental results, HEE under controlled dual pressure is also lower. Therefore, before applying the results of thermal simulation experiments to unconventional and deep oil/gas evaluation, sufficient attention should be paid to the pressure conditions of the experiments. Within the oil window, when the temperature and hydrostatic pressure of source rocks are dropped due to tectonic events such as uplift, they can discharge more oil and gas than before uplift, as a consequence of adjustment of overpressured fluid to re-equilibrate to the adjacent hydrostatic conditions. In addition, during pressure and temperature reduction, the expelled fluids have a higher gas to oil ratio. This helps to indicate that sedimentary basins that experienced tectonic events still have great exploration potential. The temperature program, pressure setup, expulsion conditions in the two-series experiments is a tentative work tested on a representative source rock from the Triassic Yanchang Formation (Ordos Basin), indicating that control of fluid and lithostatic pressure are essential for improving the accuracy of thermal simulation predictions. The dual-pressure pyrolysis apparatus has high exploration relevance, particularly when quantitative results are integrated with the depositional, tectonic and thermal histories of specific source rocks.

The Wufeng-Longmaxi (WL) shale is widely distributed in the Sichuan Basin and adjacent areas in southwest China. The basin experienced multiple-stage complex tectonic movements, whose influences on burial, thermal maturation and gas generation histories in different areas are poorly understood. Based on a detailed study of the denudation stages, strata thickness, and thermal history of the basin, burial and thermal maturation histories of seven wells in different areas were modelled using PetroMod software. Due to the high maturity of the WL shale, a low-maturity Silurian Polish Llandovery shale was used for gold tube closed-system pyrolysis experiments to obtain kinetic parameters for evaluating methane generation history. The Polish shale was selected due to its depositional age, sedimentary environment and organic type, which are similar to the WL shale. The burial history of the WL shale can be divided into five stages: I. Early to Middle Silurian rapid burial; II. Caledonian uplift and denudation; III. Permian to Triassic sustained burial and denudation; IV. sustained burial since the Late Triassic; and V. Late Cretaceous to present sustained uplift and denudation. The thermal maturity of the WL shale in all wells increased with burial depth during stage IV. In addition, high calculated reflectance increments in wells JY1 and N201 during stage III occurred due to the relatively high basal heat flow and deep burial depth, resulting in higher current thermal maturities than in the other wells. The late Permian-Early Triassic and the Middle Jurassic-Early (or Late) Cretaceous were the key methane generation periods for wells JY1 and N201. In contrast, the other five wells had a single methane generation stage, mainly determined by burial and thermal maturation processes. The time of uplift and the amount of denudation during stage V, the current burial depth, the development of faults and fractures, high proportion of retention and the seal capacity of the overlying caprock are key factors for shale gas preservation. Hence, this study will help guide future shale gas development in the Sichuan Basin.

Shale oil is a significant alternative energy, and in-situ conversion technology can achieve large-scale yield. The objective is to investigate the activation energy characteristics of kerogen at different maturities and total organic carbon contents. The study compared the activation energy of shale, kerogen and retained oil. The correlation between organic matter structure and in-situ conversion mechanism were also studied. In order to achieve the above objectives, the Chang 7 Formation in the Ordos Basin was used as an example. The methods include open and semi-open hydrocarbon generation thermal simulation experiment, Fourier transform infrared spectroscopy, solid-state nuclear magnetic resonance and other tests. The results indicate that the hydrocarbon generation in natural and artificially simulated kerogen samples are similar at low maturity. The proportions of low and main activation energy groups decrease with maturity, while those of high activation energy groups increase. TOC has an impact on activation energy but is not the primary factor. The proportion of low activation energy groups at different maturity stages is greater in shale than in kerogen. The activation energy of retained oil is smaller than that of shale. The activation energy increases sequentially for retained oil, shale and kerogen. The area of aliphatic carbon is significantly greater than that of aromatic carbon at low maturity. With increasing maturity, the areas of both gradually converge, and aromatic carbon surpasses aliphatic carbon by Ro around 1.1 %. Aromatic carbon and hydroxy/carboxylic carbon are mainly derived from the consumption and transformation of aliphatic carbon. The aliphatic carbon structure is mainly composed of methylene carbon, and aromatic structure coexists as single and multiple rings. There is no significant aromatic ring condensation in the maturity Ro = 0.5 similar to 1.1 %. Different maturities affect the structure of kerogen, with TOC having a small impact. As the thermal maturity increases, the increase in the aromatic component leads to a gradual increase in the proportion of average and high activation energy groups. HI, H/C and fali exhibit a decreasing trend with maturity, indicating a reduction in the hydrocarbon generation potential. The study conducted novel experiments, which can provide a scientific basis for the in-situ conversion process of shale.

Industrial quantities of tight gas from the Carboniferous Benxi Formation have been found in the southern Ordos Basin. The source and contributions from mudstone and coal in the Benxi Formation to the tight gas are still unclear, and the hydrocarbon generation potential and kinetics of the Benxi Formation mudstone have rarely been reported, which has halted resource evaluation of tight gas. Confined pyrolysis experiments were performed to determine the yields and kinetic parameters for gaseous hydrocarbon formation for a representative sample of a Benxi Formation mudstone from the Ordos Basin, with a hydrogen index (HI) of 137 mg/g TOC and T-max of 434 degrees C. The maximum yield of C-1-C-5 hydrocarbons is 143 mg/g TOC. For samples with similar HI, Upper Paleozoic mudstone samples might have a higher total gas generation potential than Upper Paleozoic coal samples because of the more reducing environment during mudstone deposition, which is beneficial for the preservation of sedimentary lipids. Even though the HI of Upper Paleozoic coals is apparently higher than that of Upper Paleozoic mudstones, they have a similar late gas generation potential. Basin modeling shows that the amount of natural gas generated from Benxi Formation mudstone increases southward. Coaly source rocks from the Ordos Basin with a lower oil generation potential have more negative delta C-13(1) values when the vitrinite reflectance is lower than 1.4-1.7%. This phenomenon might be related to the more negative delta C-13 of wet gas or the small hydrocarbon molecules incorporated into the kerogen compared with the components generating primary cracking gases. This study deepens the understanding of gaseous hydrocarbons generated from mudstone and coal in transitional depositional environments and provides the key parameters for tight gas resources in this area.

The cracking and stability of liquid oil is of critical importance in the exploration of deep petroleum accumulations. Numerous studies have been conducted on oils to investigate the cracking process. However, limited research has been directed to the cracking of oil with different maturities. Here, gold tube pyrolysis experiments were conducted on lower maturity normal oil (LMO) and higher maturity condensates (HMC) samples to investigate the compositions of pyrolysis products and to estimate the stability of oil during continuous deep burial. The results indicated that oil cracking can be generally divided into two stages, namely light oil generation stage and gas generation, with a maturity boundary approximately EasyRo ∼1.5%. Most of oil cracking gas was generated at EasyRo ∼ 2.4 %, with maximum mass yield of C1-5 is 553.8 mg/g and 609.4 mg/g for LMO and HMC, respectively. The difference in gas yields between HMC and LMO indicates the higher gas potential during the cracking of light oil components. An obvious increase in the C19/C23 tricyclic parameters was observed with enhanced thermal maturity, which indicates the interpretation of tricyclic parameters of high mature oils should be made with caution. Although high maturity also influenced the ratios of gammacerane/αβ C30 hopane (G/H) and 4-methylsteranes/C29 steranes (4MSI), the altered corresponding values still fall within the suggested discriminating zones for the Dongying and Shahejie Formation source rocks. Thus, the G/H and 4MSI parameters can be utilized to characterize the high mature oil with Ro <1.3% in the Bohai Bay Basin (BBB) or other basins. The calculated activation energy of C1-5 generation for LMO displays a more discrete and lower distribution compared to the HMC, which may indicate relatively lower stability heavy hydrocarbons in LMO. Based on previous studies of petroleum charge, the kinetics of C1-5 generation of LMO were extrapolated to geological conditions, yielding a maximum depth of 5750 m for the occurrence of liquid oil in the BBB. This study underscores the high thermal stability of light oil fractions, which indicates that deep high mature oils may represent the preservation of directly charged light oil or the transformation by in-reservoir cracking of normal oil associated with continuous burial.

Paleozoic coals within the Ordos Basin are believed to be the primary source rock for natural gas produced from these strata. However, the influence of potential marine environments on their hydrocarbon generation potential and processes remains underexplored. This study addresses this knowledge gap by employing organic geochemical methods, high-pressure pyrolysis (gold-tube pyrolysis), and basin modeling. The results reveal significantly higher total sulfur (TS) contents in Taiyuan and Benxi Formation coals compared to those in Shanxi Formation coals. This difference might suggest a strong marine influence on the former two formations. The influence of marine environments on the hydrocarbon generation potential exhibited limited effects across the entire coal sample set, possibly due to the scarcity of samples with Tmax values in the 445-460 degrees C range. However, for coals with similar Tmax ranges (461-470 and 471-480 degrees C), marine-influenced Benxi and Taiyuan Formation coals displayed higher hydrogen index (HI) values compared to nonmarine Shanxi Formation coals. This might suggest a potential extension of the maturation process by marine influence. Benxi Formation coals exhibited a greater hydrocarbon generation potential than Shanxi Formation coals at a thermal maturity below 1.0%. This may be attributed to lower activation energy in marine-influenced coals due to weaker S-S and C-S bonds, facilitating the formation of active sulfur radicals during maturation. Additionally, the rearrangement of sulfur moieties in residual kerogen of Benxi Formation coals might enhance thermal stability and elevate the gas generation potential at thermal maturity exceeding 3.5%. These findings hold implications for coalbed methane exploration in the Shenmu-Fugu region of the Ordos Basin and areas within the Qinshui Basin exhibiting thermal maturity exceeding 3.5%.

High concentrations of thiadiamondoids together with elevated H2S are indicative of the occurrence and extent of thermochemical sulfate reduction (TSR). However, the obscure formation mechanism and accumulation timing of thiadiamondoids restricts their application in TSR evaluation. In this study, TSR simulation experiments with MgSO4 and three model compounds, namely adamantane, 1-methyladamantane, and diamantane, were performed in gold tubes in high pressure reactors. The gaseous hydrocarbons and liquid products generated from the model compounds by TSR were identified and quantified. According to the H2S yields from the three model compounds, the susceptibility to TSR of three model compounds is 1-meththyladamantane > adamantane > diamantane. Four types of compound groups with diamondoid structure were detected in the liquid products: from high to low abundance these are diamondoidyl ketones, diamondoidyl alcohols, diamondoidthiols and thiadiamondoids, respectively. Thiadiamondoids can be generated from C0-alkylated diamondoid species by TSR. During the TSR process, the concentrations of both diamondoidyl alcohols and diamondoidthiols first increased within the maturity range 0.89-1.09 Easy%Ro and then decreased at maturity > 1.09 Easy%Ro. The rapid decrease in concentration of diamondoidthiols does not correspond to increasing thiadiamondoids, suggesting that diamondoidthiols may not be reaction intermediates for thiadiamondoids in laboratory experiment conditions. In the TSR simulation experiments, slowly increasing concentrations of diamondoidyl ketones correspond to slowly increasing concentrations of thiadiamondoids. For the synthesis mechanism of thiaadamantanes derived from thiaadaamantane-4,8-dione, we propose that the diamondoidyl ketones could be reaction intermediates in thiadiamondoid formation. The thiadiamondoids in petroleum could have two different formation mechanisms: (1) low-temperature cationic carbon ion rearrangement in diagenesis to early catagenesis stages, in which thiadiamondoids are derived from the diagenetic products of polycyclic thiols in the source rock; and (2) a free sulfur radical mechanism that occurs in the TSR process at high temperature in the middle catagenesis to metagenesis stages. During the TSR process, free sulfur radicals attack the diamondoidyl ketones generated in the first stage of TSR and open the cage structure. Then the carbonyl carbon atom is replaced by a sulfur atom, followed by cyclization to form thiadiamondoids. Based on the H2S yields in the TSR simulation experiments with diamondoid model compounds, most thiadiamondoids formed in the second stage of the autocatalyzed TSR process within the maturity range of 1.09-1.21 Easy%Ro.

Based on the thermal simulation experiment in a semiclosed system, the products of continental type II of the Chang 7 shale under slow and fast heating rates were studied. The results show that the yield of hydrocarbon gases (C-1-C-5) increases under the fast heating rate. Under the slow heating rate, the heavy hydrocarbon gas (C-2-C-5) begins to crack when the temperature exceeds 400 degrees C. The H2S and H-2 have similar variation rules with hydrocarbon gases. Under the slow heating rate, the expelled oil is larger than that of the fast heating rate. C15+ constitutes the main component of retained oil, and the yield of retained oil at the fast heating rate is larger than that of the slow heating rate, which is different from the expelled oil. After 380 degrees C, the slow heating rate leads to the cracking of C15+, so the amount of C15+ generated by the fast heating rate is larger than that of the slow heating rate. After 340 degrees C, the proportion of expelled oil to total expelled hydrocarbons at a slow heating rate is larger than that of the fast heating rate. This study confirms that the fast heating rate can lead to a retardation effect, making the slow heating rate more favorable for the generation and discharge of hydrocarbons. The experimental results verify the compensation effect of time on temperature in the process of hydrocarbon generation.

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 EC21_/EC22+ is higher in lamina scale reservoir but lower in lithofacies scale reservoir. It is assumed that the low-molecular weight n-alkanes also follow mo-lecular fractionation. The lithofacies reservoir has a lower EC21_/EC22+ 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 EC21_/EC22+, carry the same maturity signature as EC21_/EC22+. 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 solvent extracted bitumen (EB) and microscopically observed solid bitumen (SB) carry many geological implications in unconventional source-rock reservoirs. EB is a commonly used term in organic geochemistry, and SB is normally used in organic petrology. Although both EB and SB are secondary organic matter initially formed from kerogen degradation and partially describe the same components, they are defined by different physical and chemical criteria and have specific applications, and thus are rarely comparatively investigated. In this study, by taking the shale of the seventh member of the Upper Triassic Yanchang Formation in the Ordos Basin, China, as a case study, we performed an integrated characterization on the two types of bitumen. The characterization was carried out on source rocks and reservoir assemblages at two scales: lamina-scale (organic-rich lamina and silty lamina) and lithofacies-scale (shale and sandstone). Programmed temperature pyrolysis (Rock-Eval 7 pyrolysis), gas chromatography-mass spectrometry (GC-MS), and Raman spectroscopy were used in this study. The samples are distributed within a 12 m interval and therefore should have experienced the same degree of thermal stress. However, maturity parameters derived from GC-MS for EB and Raman spectroscopy for SB exhibit a different inferred thermal maturity between source rocks and reservoirs at both lithofacies- and lamina-scales. The sidechain scission reactions related (non-)biomarker parameters such as Ts/C30H, sigma nC21_/sigma nC22+ alkanes, relative C21 + C22 sterane content and TA(I)/TA(I + II) suggest higher thermal maturity in source rocks (shale and organic-rich lamina) than the corresponding reservoirs (sandstone and silty lamina), while Raman-derived parameters RBS and G-FWHM indicate higher maturity in reservoirs than the corresponding source rocks. It is speculated that the EB measured by GC-MS comprises saturated and aromatic components corresponding to relatively mobile hydrocarbons. The maturation of the source rock exerts greater control over this component than that of the reservoir. In comparison, the SB measured using Raman spectroscopy mainly consists of solid residue left behind after migration and/or decomposition of a once-liquid oil phase that is less readily able to move. It is more intensely altered by the organic-inorganic interactions (mineral dissolution-precipitation processes) in the reservoir than that in the source rock, resulting in a consolidated SB with higher aromaticity. The storage ability of silty lamina in shale may complicate the data interpretation of geochemical differences in EB- and SB-derived parameters. On a practical note, when assessing thermal maturity, taking into the account the lithology or rock texture, which affects the organic-inorganic interactions, as well as specific components detected by different techniques may provide helpful clues to explain some contradictory results.

The differences between the Rock-Eval pyrolysis results of powder and grain samples have attracted wide attentions. Grain samples show lower hydrocarbon yield and different composition of the products. However, the effect of grain size on hydrocarbon generation and expulsion has not yet been quantitatively evaluated. In this study, we prepared each grain into a regular column with precise geometric parameters such as diameter, height, surface area, and volume, which is defined as an independent unit of hydrocarbon generation and expulsion. For comparison, a powder sample corresponding to each grain sample is collected simultaneously during the preparation process. The grain samples are used to simulate the mass of hydrocarbons expelled, while the powder samples are used to simulate the total mass of hydrocarbon generated. Our results show significant differences between the grain samples and the powder samples. All powder samples have a higher expulsion of free hydrocarbons (S1) than grain samples, and almost all grain samples have a higher expulsion of pyrolysis hydrocarbons (S2) than powder samples when the diameter of the grains is smaller than 3 mm. Temperature controls hydrocarbon generation, but grain size retards hydrocarbon expulsion. The influences of the "carry-over" phenomenon, oil adsorption and nanopore confinement are enhanced by grain size, which retards and inhibits hydrocarbon expulsion. Some free hydrocarbons (S1) cannot be expelled from the grain samples at 300 degrees C. Parts of the retained free hydrocarbons (S1) further cracked into small molecules, which can be expelled and detected as pyrolysis hydrocarbons (S2) at 300-650 degrees C. Four new parameters were proposed to quantify these influences, namely the S1retained, the S2extra expulsion, the HI difference parameter, and the TOC difference parameter. Diameter is more closely related to hydrocarbon expulsion rather than height. For grain samples, HI increases and TOC decreases with increasing diameter. Activation energies for hydrocarbon generation ranges from 43 to 67 kcal/mol for powder samples, while activation energies for grain samples are almost concentrated in 54-55 kcal/mol, indicating a high expulsion threshold for grain samples. As the grain diameter increases from 1.74 to 5.24 mm, the transformation ratio decreases and the generation rate increases, indicating that the grain size delays the expulsion of hydrocarbon. This laboratory simulation provides some new results to better understand the hydrocarbon generation and expulsion of shale rock under natural conditions.

In this study, gold tube thermal simulation experiments were carried out on the soluble components (extracts) and insoluble components (extracted coal-measure mudstones) of coal-measure mudstones, and diamondoid compounds in the pyrolysis products were quantitatively analyzed. The results showed that diamondoid compounds in the extracts and the extracted coal-measure mudstones had undergone the process of formation and decomposition during thermal evolution. Based on the quantitative composition of the extracts and the extracted coal-measure mudstones, the calculated evolution characteristics of the diamondoid compounds in the coal-measure mudstones were mainly consistent with the results of thermal simulation experiments, indicating that the formation of diamondoid compounds was primarily controlled by the original material source. Some diamondoid maturity parameters (MAI, EAI, TMAI-1) in coal-measure mudstones were consistent with the parameters of the evolution characteristics in marine shale. Therefore, the relationship between these parameters and vitrinite reflectance can be established, to calculate the maturity of marine source rocks. In addition, the evolution characteristics and some diamondoid maturity parameters in the extracts and the extracted coal- measure mudstones showed a good linear relationship, but the specific characteristics were different, which may enable the identification of kerogen cracking and secondary cracking of crude oil.

A semi-open thermal simulation of hydrocarbon generation experiment was conducted on the lacustrine Type II rocks (the Chang 7 member shale in the Ordos Basin, China). Geochemical characteristics of the hydrocarbon and non-hydrocarbon gas were studied. The yield of hydrocarbon and non-hydrocarbon gas is approximately the same in the whole process of hydrocarbon generation. The cumulative and net increased yield of the hydrocarbon gas were measured and quantified. Gas generation stages are divided and the source of the generation of different gases are studied. Carbon isotopic values of gases generated were tested. The pyrolysis residues at each temperature point were collected and subjected to routine pyrolysis analysis. Based on the experiment, the gas generation can be divided into 3 stages, and different stages have different gas source.

For identifying the occurrence and extent of thermochemical sulfate reduction (TSR) reaction of natural gas and better understanding the chemical and carbon isotopic variations in natural gas reservoirs, high-pressure hydro-pyrolysis with a special designed apparatus was performed using natural gas and various amounts of MgSO 4 ·7H 2 O at up to 360 °C. The yields, chemical and isotopic compositions of the gases produced during TSR and thermal cracking were measured. As the extent of TSR reaction increased, the concentrations of CH 4 , CO 2 and H 2 S increased in a nonlinear way, while those of C 2 H 6 and C 3 H 8 decreased. According to the variation of gas content, the TSR reaction of alkane gases can be divided into an uncatalyzed and a catalyzed stage, which is different from previous studies that treated the TSR reaction of alkane gases as a non-autocatalytic reduction process. As the concentration of MgSO 4 ·7H 2 O increased, the rate of TSR reaction with hydrocarbon gases increased. The concentrations of HSO 4 − and volume of aqueous phase could be responsible for the different TSR reaction rates in the catalyzed stage. The co-variation of ln(C 1 /C 2 ) and ln(C 2 /C 3 ) could be related to the TSR reaction of alkane gases. Our study provides clues for understanding the compositional variations in natural conditions.