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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 °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 °C. Four new parameters were proposed to quantify these influences, namely the S1 retained , the S2 extra 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. • The effect of shale grain size on hydrocarbon generation and expulsion was studied using Rock-Eval and kinetics. • With diameter increasing,the results of grain size and powder samples based on Rock-Eval pyrolysis show regular differences. • Grain size enhances the "carry-over" phenomenon, oil adsorption, and nanopore confinement. • Larger grain size samples have lower transformation ratios and generation rates due to the high expulsion threshold. [ABSTRACT FROM AUTHOR]

The last decade witnessed rapid growth of shale oil and gas production. Increasing numbers of shale reservoirs have been explored and developed. Since hydrocarbon generation is an important process in forming a shale reservoir, it has attracted great attention from researchers. However, previous works mainly focus on geochemical changes during the hydrocarbon generation process, and investigations of the change of other parameters are insufficient. In this study, we intend to fill this gap in the literature by examining the mechanical properties evolution of organic-rich shales during an artificial hydrocarbon generation experiment. Continuous stiffness measurement (CSM) and microindentation test are used to measure the mechanical properties of rocks. The result of CSM shows the influence of indentation depth on Young's modulus. Three stages are identified, and a displacement of 4000 nm–6000 nm is determined to be appropriate for measuring bulk mechanical properties. Microindentation results of shales at different hydrocarbon generation stages exhibit a hill-like trend. The Young's modulus with an initial value of 42.15 GPa increases as the hydrocarbon generation proceeds, reaches a maximum value of 46.49 GPa, and then begins to decrease and reaches the lowest value of 37.41 GPa. Indentation hardness and estimated fracture toughness by an energy-based method show similar trends to Young's modulus. Scanning electron microscope observation of post-hydrocarbon-generation samples may provide an explanation of the hill-like trend. • Young's modulus variation with displacement can be identified as three stages. • Young's modulus exhibits a hill-like trend as hydrocarbon-generation proceeds. • Relationships between Young's modulus, indentation hardness and fracture toughness are explored. [ABSTRACT FROM AUTHOR]

In order to investigate the effects of water pressure on hydrocarbon yields and potential in source rocks, carbonaceous mudstone from drilling in Liaohe Basin was pyrolyzed in simulation with constant water pressure and high-water-pressure experiments. Results demonstrate that the times of expelling hydrocarbon remarkably promote source rocks yielding liquid hydrocarbons. Increasing water pressure may increase the reaction of generating bitumen and oil, and enhance liquid hydrocarbons generation. Results of TOC, Rock-Eval, and elemental analysis in this study suggest that carbonaceous mudstone dominated by type-III kerogen remains a large number of hydrocarbon-generating potential, which may indicate that carbonaceous mudstone has a good potential to yield deep oil and natural gas. Besides, vitrinite reflectance may be the most suitable parameter to describe the maturity of source rocks. [ABSTRACT FROM PUBLISHER]

The Lower Cretaceous lacks detailed comprehensive study of source rocks geochemistry characteristics and thermal evolution history as the target stratum of potential regional oil-gas exploration in the HaRi Sag, Yin-E Basin. Organic geochemistry methods were first applied to detailed study of organic matter content, type and maturity of Lower Cretaceous source rocks from the HaRi Sag. The results showed that the organic matter of K1Y formation Types I–II1with high content and Immature-Early mature, K1S formation kerogen Types II1–II2with relatively high content and Early-Mid Mature and K1B formation kerogen Types II2–III with low content and Late Mature-Main Gas Generation. The proposed maturity evolution history of source rocks in HaRi Sag based on EASYRO% model under the control of vitrinite reflectance (RO%) shows the maximum geothermal gradient reached 48–52°C/km and the maximum paleogeotemperature is over 190°C at the end of Early Cretaceous, and the main timing of hydrocarbon generation is 106.3–80.0 Ma. [ABSTRACT FROM AUTHOR]

The Vendian-Riphean section of the Ust’-Maiskaya-366 parametric well was studied. The well is the first deep well drilled in the central part of the Aldan-Maya depression, in the southeast of the Siberian Platform. New probable oil source rocks within the Upper and Middle Riphean deposits have been identified based on core analysis supported by geological-survey data. We make a geochemical description of organic matter from these deposits and report the composition of abundant migrated bitumens discovered in the Ust’-Maiskaya-366 well section. The petroleum content in the Aldan-Maya depression has been predicted with regard to the new geological and geochemical data. [ABSTRACT FROM AUTHOR]

Programmed pyrolysis experiments investigating the influence of the mineral matrix on hydrocarbon generation from organic compounds have shown inconclusive results in past studies. This study tests the hypothesis that the inhibitory vs catalytic influence of clay minerals is dependent on the physical association of the mineral matrix with organic compounds by comparing natural samples from two shale formations with different mineral-organic associations. Samples from the Miocene Monterey Formation have a greater area of surface contact between organic matter and mineral surfaces when compared to the more particulate texture and discrete nature of the organic matter in the samples from the Permian Stuart Range Formation. Comparison of kerogen extracts to the whole rock (containing mineral and organic matter) samples during programmed pyrolysis shows higher hydrocarbon generation from isolated kerogen compared to the whole rock sample it was extracted from in both the Monterey and the Stuart Range Formation samples. The difference between extracted kerogen and whole rock samples is greater and more variable (56–210 mgHC/gTOC) in the Stuart Range than the Monterey Formation (85–142 mgHC/gTOC) implying greater hydrocarbon retention by the free mineral surfaces. The temperature of maximum hydrocarbon generation (Rock-Eval T max ) is greater in whole rock than kerogen isolates (20 °C mean) in the Monterey Formation samples, but shows negligible difference (2 °C mean) in the samples from the Stuart Range Formation. Standard kerogen typing using Rock-Eval pyrolysis data places the same kerogen as Type II to Type III on a modified Van Krevelen diagram depending whether it is isolated or pyrolysed with its mineral host. This study identifies that not only the bulk mineralogy and kerogen type but also the degree of surface contact of the phases influence hydrocarbon generation. [ABSTRACT FROM AUTHOR]

Samples of argillaceous source rocks from three sub-members of the Shahejie Formation (Es) in the Dongying Depression, China, were collected to investigate the differences in hydrocarbon generation among the sub-members, which developed in fresh (Es 3 2 , Es 3 3 ) and saline (Es 4 1 ) water environments. Pyrolysis, XRD and thermo-XRD analyses were used to compare the characteristics of organic matter (OM), clay minerals and OM occurrences. Total organic carbon and hydrocarbon potential proxies suggest that the samples from Es 3 3 were much better than the other two intervals, which agrees with previous studies. The characteristics of clay minerals suggest that the samples from Es 4 1 have the most abundant illite, with a maximum illite percentage in mixed-layer illite-smectite (I Sm), and the best crystallinity of I Sm with a main stacking mode of R1.5. However, the stacking modes of I Sm in Es 3 2 and Es 3 3 were primarily R0 and R1, respectively, and the crystallinity was relatively poor. Thus, the smectite illitization process was faster in Es 4 1 than in the other two intervals, and a saline environment was a primary cause for the acceleration of the process. Moreover, OM occurrence indicates that the samples from Es 4 1 had the lowest amount of interlayer OM, whereas Es 3 3 had the largest amount. Therefore, the rapid illitization in Es 4 1 caused abundant interlayer OM to be desorbed and discharged, which in turn caused the amount of residual interlayer OM in Es 4 1 to be less than that in the other two intervals. Thus, the source rocks of Es 4 1 made a more significant contribution to hydrocarbon generation than those of the other two units. In conclusion, the inconsistent illitization among these intervals was a major cause of the differences in hydrocarbon generation. [ABSTRACT FROM AUTHOR]

Coalbed methane (CBM) is mainly stored in coal by adsorption and tectonism is an important factor affecting the storage state of CBM. In order to gain a deeper understanding of the mechanism of the influence of tectonism on CBM formation, the chemical structure and hydrocarbon properties of tectonic coal and their effects on gas adsorption capacity were investigated. The results showed that the A (CH 2)/A (CH 3) values of tectonic coal decreased by 4.0%–64.1% after tectonism, and the aromaticity (I) and condensation degree of aromatic rings (DOC) increased up to 4.0 and 2.58 times, respectively. The interlayer spacing (d 002) and number of stacked layers (N ave) of aromatic ring layers decreased slightly, but the extension height (L a) increased by a maximum of 6.0%. The tectonism not only promoted the shedding of aliphatic side chains and reduction of aliphatic carbon content, but also promoted the aromatic structure of coal developed in an orderly direction. The increase in the polycondensation of aromatic structure of tectonic coal indicated a higher gas adsorption capacity than intact coal. The hydrocarbon generation potential of tectonic coal is lower than that of intact coal, which indicates that tectonic coal produces more hydrocarbons during geological formation and increases the coalification degree of coal. The chemical structural of coal has also been shown to promote gas adsorption. • Chemical structure characteristics of tectonic and intact coals were systematically characterized. • The effects of tectonism on pyrolysis hydrocarbon generation potential were systematically investigated. • The chemical structure of coal is closely related to the gas adsorption capacity. [ABSTRACT FROM AUTHOR]

The thermal history of the Melut rift Basin was studied in a number of wells and along a northeast-southwest cross sectionacross the basin using 1-D and 2-D basin models. Modelling was conducted using PetroMod software to test subsidence, thermal history and their implications for hydrocarbon generation, migration and accumulations. Geotherms were found ranging between 24 and 44 °C/km and average 32 °C/km and present day heat flow was found to vary between 53 and 65 averaging 59 mW/m 2 . A geologicaly realistic paleoheat flow model with higher heat flow peaks of 75, 70 and 65 mW/m 2 during the first, second and third rifting phases respectively, calibrated against vitrinite reflectance data was employed. The model was found sensitive to Cenozoic erosions and a 600 m of exhumation did support the vitrinite data in providing a reasonable fit in most locations. Using the Easy %Ro vitrinite kinetic model for maturity the average present day oil window was found between 1565 and 4050 m in the wells studied and between 1705 and 4200 m along the cross section. Using type-II kerogen for the Aptian-Albian source rocks, the hydrocarbon generation and expulsion were modelled and revealed that the generation started as early as 95 Ma in some areas but significant generation rates were during the second rifting phase and expulsion started at around 85 Ma. Calculations of the probable expelled amounts of hydrocarbon from the northern sub basin are high and up to 2.2 × 10 11 bbls of oil and 2.3 × 10 14 ft 3 of gas. Migration of oils from Cretaceous source rocks kitchen to the Cenozoic traps was probably through faults, porous carrier beds and breaching of traps cap rocks. The filling of these traps might be periodic during the rifting episodes and hydrocarbons remigrated from deeper traps to shallow ones. It is possible that thinner and siltier cap rocks along the hydrocarbon migration path, may have allowed gas to scape but holded the oil back. It is most probable that part of the hydrocarbons might have been generated from shallower source rocks areas and a 2-D hybrid Darcy-Flow path model have demonstrated this and predicted a number of accumulations which are similar to the known large discoveries such as Palogue-Fal and Adar-Yale oil fields. [ABSTRACT FROM AUTHOR]

This study presents a 2D basin model along a transect crossing the on- and offshore Tarfaya Basin, Morocco, in SE-NW direction. The aim of the project is to investigate the thermal evolution of the basin fill and its influence on the petroleum system. The modelling is based on a recently interpreted seismic section and includes new and published geochemical and organic petrological data from five wells. Core samples and cuttings provide information, which was used for thermal calibration of the model. Vitrinite reflectance in the Jurassic offshore basin fill reaches more than 1%. The modelled subsidence history, in combination with kinetic and geochemical data, were used to model hydrocarbon generation. In order to investigate the temperature, hydrocarbon generation and its timing, two 1D geohistory curves were extracted, one for the onshore inner shelf and one for the offshore deep water area. The modelling results suggest that deepest burial in the modern offshore area occurs at present day, whilst deepest burial in the onshore area occurred during the Oligocene depending on the location on the inner shelf. Based on the burial- and thermal evolution, significant hydrocarbon generation from Lower Jurassic source rocks took place from the Early Cretaceous until the Neogene in the offshore area. In the onshore area, petroleum generation ceased in the Late Cretaceous. As salt deposition may play an important role in the thermal history in the Tarfaya Basin, a second model including salt was built, indicating increased Early Cretaceous hydrocarbon generation in the offshore area. [ABSTRACT FROM AUTHOR]

Hydrous pyrolysis experiments were conducted on immature petroleum source rocks to define the roles of pressure and hydrocarbon expulsion in deep petroleum formation. This study can contribute to estimating the deep oil and natural gas prospects of lacustrine type-I kerogen and has important implications for deep petroleum exploration. The simulation temperature was 450 °C and the heating duration was 48 h. Water pressure ranged between 50 and 1200 bar, and lithostatic pressure ranged between 125 and 2000 bar. Under semi-closed conditions, increasing water pressure leads to more oil and less gaseous hydrocarbons being generated in the source rocks. The dryness of the hydrocarbon gas primarily confirms that increasing water pressure decreases the cracking magnitude of oil, which may indicate that high water pressures retard oil cracking. The decreasing contents of S 2 , HI and H/C in the solid residue confirm that high water pressure enhances the efficiency of hydrocarbon generation. Oil cracking is enhanced in the 125–625 bar lithostatic pressure range, probably because the pyrolysis conditions gradually approach those of a closed-system. The increasing gaseous hydrocarbon yields also confirm the accelerated cracking of oil within this pressure range. As lithostatic pressure increased from 625 to 2000 bar, the decreasing trends in oil and gaseous hydrocarbon yields indicate that hydrocarbon generation rate was retarded by high pressure within the closed system. The values of S 2 , HI, H/C, R o and T max in solid pyrolysis residue confirm that high lithostatic pressure reduces the efficiency of hydrocarbon generation and maturation. Furthermore, hydrocarbon expulsion greatly impacts hydrocarbon generation within the source rocks. Increasing water pressure increases the effect of hydrocarbon expulsion and causes the pyrolysis conditions to gradually approach an open system; this phenomenon lowers the gas yields but increases oil yields. Increasing lithostatic pressure from 125 to 625 bar decreases the effect of hydrocarbon expulsion and causes the pyrolysis conditions to steadily approach a closed system, thereby lowering the oil yield but increasing gas yield. The results demonstrate that different pressures clearly have different effects on hydrocarbon generation in the source rock, and hydrocarbon expulsion also has a significant influence on hydrocarbon generation in source rock. More importantly, this study shows that the lacustrine type-I kerogen has a good potential to yield deep oil and natural gas. [ABSTRACT FROM AUTHOR]

The Barents Sea is believed to have been influenced in most parts by Cenozoic uplift and erosion episodes. The rocks in the area are not currently at their maximum burial depth. The exhumation of the sedimentary rocks has had large effects on rock physical properties and hydrocarbon maturation and migration. The current study seeks to estimate exhumation from shale compaction and thermal maturity techniques and discuss its implications for hydrocarbon exploration in the uplifted Barents Sea area. This study uses well logs and thermal maturity data together with widely distributed shot gather data along long-offset seismic reflection lines. The use of shale compaction techniques to estimate exhumation was focused particularly on the regionally preserved Aptian-Albian (Kolmule Formation) and Paleogene (Torsk Formation) shales. Normal compaction reference curves were established for these units in areas currently at their maximum burial depth (e.g. Sørvestsnaget Basin and Vestbakken Volcanic Province). The results suggest widespread Cenozoic exhumation throughout the southwestern Barents Sea. The exhumation magnitudes increase towards east and northeast. The average exhumation estimates from the three data sources range from ∼800 to 1400 m within the Hammerfest Basin, ∼1150–1950 m on the Loppa High, ∼1200–1400 m on the Finmark Platform and ∼1250–2400 m on the Bjarmeland Platform. The marked differences in glacial erosion from mass balance and average erosion estimates from the current study suggest a significant pre-glacial uplift and erosion in the southwestern Barents Sea area. The observed stratigraphy and presence of significant volumes of Late Oligocene-Middle Miocene sediments in basins at the outer margin, and increased erosion rates at the same time in source areas suggest that maximum burial in the southwestern Barents Sea may have occurred sometime during the Oligocene, or even earlier in the Eocene. The results from this study are useful input for modelling of source rock maturation, generation, migration and trapping of hydrocarbons in the area. These results are also an important input for the prediction of more precise reservoir and seal rock properties in frontier areas away from the exploration wells and provide valuable knowledge for the use of interval velocities in the uplifted areas. [ABSTRACT FROM AUTHOR]

This study presents results for pyrolysis experiments conducted on immature Type II and IIs source rocks (Kimmeridge Clay, Dorset UK, and Monterey shale, California, USA respectively) to investigate the impact of high water pressure on source rock maturation and petroleum (oil and gas) generation. Using a 25 ml Hastalloy vessel, the source rocks were pyrolysed at low (180 and 245 bar) and high (500, 700 and 900 bar) water pressure hydrous conditions at 350 °C and 380 °C for between 6 and 24 h. For the Kimmeridge Clay (KCF) at 350 °C, Rock Eval HI of the pyrolysed rock residues were 30–44 mg/g higher between 6 h and 12 h at 900 bar than at 180 bar. Also at 350 °C for 24 h the gas, expelled oil, and vitrinite reflectance (VR) were all reduced by 46%, 61%, and 0.25% Ro respectively at 900 bar compared with 180 bar. At 380 °C the retardation effect of pressure on the KCF was less significant for gas generation. However, oil yield and VR were reduced by 47% and 0.3% Ro respectively, and Rock Eval HI was also higher by 28 mg/g at 900 bar compared with 245 bar at 12 h. The huge decrease in gas and oil yields and the VR observed with an increase in water pressure at 350 °C for 24 h and 380 °C for 12 h (maximum oil generation) were also observed for all other times and temperatures investigated for the KCF and the Monterey shale. This shows that high water pressure significantly retards petroleum generation and source rock maturation. The retardation of oil generation and expulsion resulted in significant amounts of bitumen and oil being retained in the rocks pyrolysed at high pressures, suggesting that pressure is a possible mechanism for retaining petroleum (bitumen and oil) in source rocks. This retention of petroleum within the rock provides a mechanism for oil-prone source rocks to become potential shale gas reservoirs. The implications from this study are that in geological basins, pressure, temperature and time will all exert significant control on the extent of petroleum generation and source rock maturation for Type II source rocks, and that the petroleum retained in the rocks at high pressures may explain in part why oil-prone source rocks contain the most prolific shale gas resources. [ABSTRACT FROM AUTHOR]

The hydrocarbon accumulation model of Ordovician reservoirs in the Tazhong area, Tarim Basin, was investigated based on the analysis of the key factors controlling hydrocarbon generation, migration, and enrichment process and history. The results show that the hydrocarbon generation processes are controlled by Cambrian-Lower Ordovician and Upper Ordovician source rocks distributed in the Tazhong area and the Manjiaer Sag. Vertical hydrocarbon migration distance is controlled by the vertical source-reservoir distribution, faults, and caprocks. Structure played a major role in the lateral hydrocarbon migration along NW-SE direction. Lateral migration pathways were governed by unconformities, transport faults, and reef-beach body reservoirs. A part from the sedimentary control, hydrocarbon enrichment is controlled by recent tectonic events. The hydrocarbon charging points refer to the intersection of northeast- and northwest-trending faults. Two types of hydrocarbon accumulation models could be retained, (a) mixed-sourced area model, in which the hydrocarbons are sourced from both the Tazhong area and the Majiaer Sag, and (b) single-sourced area model, in which the hydrocarbons are only sourced from the Tazhong area itself. [ABSTRACT FROM AUTHOR]

This paper presents a numerical petroleum systems model for the Jurassic-Tertiary Austral (Magallanes) Basin, southern Argentina, incorporating the western part of the nearby Malvinas Basin. The modelling is based on a recently published seismo-stratigraphic interpretation and resulting depth and thickness maps. Measured vitrinite reflectance data from 25 wells in the Austral and Malvinas Basins were used for thermal model calibration; eight calibration data sets are presented for the Austral Basin and four for the Malvinas Basin. Burial history reconstruction allowed eroded thicknesses to be estimated and palaeo heat-flow values to be determined. Six modelled burial, temperature and maturation histories are shown for well locations in the onshore Austral Basin and the western Malvinas Basin. These modelled histories, combined with kinetic data measured for a sample from the Lower Cretaceous Springhill Formation, were used to model hydrocarbon generation in the study area. Maps of thermal maturity and transformation ratio for the three main source rocks (the Springhill, Inoceramus and Lower Margas Verdes Formations) were compiled. The modelling results suggest that deepest burial occurred during the Miocene followed by a phase of uplift and erosion. However, an Eocene phase of deep burial leading to maximum temperatures cannot be excluded based on vitrinite reflectance and numerical modelling results. Relatively little post-Miocene uplift and erosion (approx. 50-100 m) occurred in the Malvinas Basin. Based on the burial- and thermal histories, initial hydrocarbon generation is interpreted to have taken place in the Early Cretaceous in the Austral Basin and to have continued until the Miocene. A similar pattern is predicted for the western Malvinas Basin, with an early phase of hydrocarbon generation during the Late Cretaceous and a later phase during the Miocene. However, source rock maturity (as well as the transformation ratio) remained low in the Malvinas Basin, only just reaching the oil window. Higher maturities are modelled for the deeper parts of the Austral Basin, where greater subsidence and deeper burial occurred. [ABSTRACT FROM AUTHOR]

The microstructure of black siliceous shale from the lower Cambrian Niutitang Formation, Sichuan Basin in China was investigated by the combination of field emission scanning electron microscope (FE-SEM) and argon ion beam milling. The nanometer-to micrometer-scale pore systems of shales are an important control on gas storage and fluid migration. In this paper, the organic porosity in shale samples within oil and gas window has been investigated, and the formation mechanism and diagenetic evolution of nanopores have been researched. FE-SEM reveals five pore types that are classified as follows: organic nanopores, pores in clay minerals, nanopores of framework minerals, intragranular pores in microfossils, and microfractures. Numerous organic nanopores are observed in shales in the gas window, whereas microfractures can be seen within the organic matter of shales in the oil window. Microfractures in oil window shales could be attributed to pressure buildup in the organic matter when incompressible liquid hydrocarbon are generated, and the orientation of microfractures is probably parallel to the bedding and strength anisotropy of the formation. Pores in clay minerals are always associated with the framework of clay flakes, and develop around rigid mineral grains because the pressure shadows of mineral grains protect pores from collapse, and the increasing of silt content would lead to an increase in pressure shadows and improve porosity. Nanopores of rock framework are probably related to dissolution by acidic fluids from hydrocarbon generation, and the dissolution-related pores promote permeability of shales. Porosity in the low-TOC, low-thermal-maturity shales contrast greatly with those of high-TOC, high-thermal-maturity shales. While the high-TOC shales contain abundant organic microporosity, the inorganic pores can contribute a lot to the porosity of the low-TOC shales. [ABSTRACT FROM AUTHOR]

Isothermal confined (gold capsule) pyrolysis experiments were performed for coal alone, oil alone and coal plus oil with oil/coal ratios ranging from 0.006 to 0.171 at 315 °C, 345 °C and 375 °C, respectively and 50 MPa for 72 h. In the experiment for coal plus oil, the amounts and compositions of hydrocarbon gases are substantially different from those predicted from the results in the experiments for oil alone and coal alone. The results of these experiments demonstrate that kerogen and oil do not crack separately in the experiments of coal plus oil. The interaction between kerogen and oil components leads to the generation of hydrocarbon gases. With oil/coal ratio increasing, the amounts of individual and total hydrocarbon gases decrease at first, and then increase rapidly up to several times those calculated from the yields of these components in the experiments for oil alone and coal alone. The C 1 /ΣC 1–5 ratios of hydrocarbon gases decrease and are increasingly lower than those calculated from the yields of hydrocarbon gases in the experiments for oil alone and coal alone. The amount and carbon isotopes of individual n -alkane demonstrate that the free liquid n -alkanes were incorporated into kerogen and replaced the bound liquid n -alkanes (covalently bonded alkyl groups in kerogen). Carbon isotopes of hydrocarbon gases further suggest that the bound liquid n -alkanes in kerogen preferentially crack into hydrocarbon gases. [ABSTRACT FROM AUTHOR]