•76 oils are separated into two groups from individual n-alkane δ13C values.•Molecular parameters differ with some overlaps between the two oil groups.•Group I oils are mainly sourced from the Lower Permian Fengcheng Formation.•Group II oils are mainly derived from the Middle Permian Lower Wuerhe Formation.The Junggar Basin is a major oil producing province in China. Most oil reservoirs found so far in this basin are in the Mahu sag and neighboring uplifts, northwestern Junggar Basin. A total of 78 oils and 10 Permian source rocks from the northwestern and central Junggar Basin and two oils and two Permian source rocks from the eastern Junggar Basin were analyzed by GC, GC–MS and GC–IRMS. The 78 oils can be clearly classified into two groups based on these analytical results. For group I oils, δ13C values of individual n-alkanes are relatively higher and remain stable with increasing carbon number. For group II oils, these values are relatively lower and decrease at first, and then increase with carbon number. Differences in molecular parameters can be also observed between these two groups of oils. Group I oils generally have: (1) higher Pr/n-C17 and Ph/n-C18 ratios and lower Pr/Ph ratio, and (2) higher gammacerane/(C30 hopane + gammacerane) and β-carotane/(β-carotane + C30 hopane) ratios, compared with group II oils. In addition, group I oils mainly have tricyclic terpane distribution patterns with either C20 < C21 < C23 and C20 > C21 > C23 while group II oils mainly have the pattern of C20 < C21 and C21 > C23. However, molecular parameters overlap to some extent between these two groups of oils. Group I oils correlate well with the nine source rocks of the Lower Permian Fengcheng Formation (P1f), while group II oils correlate well with the three source rocks of Middle Permian age based on carbon isotopic and molecular compositions. The occurrence of these two groups of oils in the northwestern and central Junggar Basin are consistent with facies and thickness variations in the source rocks within the Lower Permian Fengcheng Formation (P1f) and Middle Permian Lower Wuerhe Formation (P2w).

Several oil and gas fields have been found in which oil and gas were mainly derived from the Jurassic coaly source rocks in the Junggar Basin, northwest China. Pyrolysis experiments were performed on two coals (J23C1 and FM1C2) and one type III kerogen of mudstone (Di9S1) from Jurassic strata in the basin at two heating rates of 20 and 2 °C/h in confined systems (gold capsules). Hydrogen indices and H/C atomic ratios of the three samples J23C1, FM1C2, and Di9S1 are 83, 197, and 226 mg/g TOC, and 0.70, 0.86, and 1.01, respectively. The measured maximum oil yields for the three samples are 59.37, 175.75, and 80.75 mg/g TOC, respectively, inconsistent with hydrogen indices and H/C atomic ratios. However, the measured maximum gas yields (∑C1–5) for the three samples are 90.69, 157.24, and 198.15 mg/g TOC, respectively, consistent with hydrogen indices and H/C atomic ratios. This result is interpreted by kerogen Di9S1 containing mainly crossed alkane moieties with both terminals attached to aromatic rings while coals J23C1 and FM1C2 contain mainly alkane moieties with only one terminal attached to an aromatic ring based on kerogen 13C NMR spectra and the oil yield relative to gas yield and compositions of liquid components produced in confined pyrolysis. The crossed alkane moieties were hardly released as liquid alkanes but likely further cracked into gaseous components during pyrolysis. Jurassic strata contain some effective oil source rocks which produced enough amount of oil required for oil expulsion and formation of commercial oil reservoirs in oil generative window (Ro 0.6–1.35%). The amounts of gaseous hydrocarbons generated from the Jurassic coaly source rocks are generally low in oil generative window due to low transformation ratios. Elevated maturity (Ro > 1.35%) is a critical controlling factor to the Jurassic coaly source rocks generating sufficient gaseous hydrocarbons and forming commercial gas reservoirs.

•Confined pyrolysis was performed on two source rocks with HI 663 and 698 mg/g TOC.•Oil yields and kinetic parameters for oil generation from these rocks vary greatly.•A method is presented to estimate gas yields from oil-prone source rocks.•Oil and gas generation in the source kitchen of the Junggar Basin was modeled.The Junggar Basin is a major oil producing province in China. Most of the oil originated from Permian lacustrine oil-prone source rocks in the basin. Kinetic parameters for oil and gas generation were obtained from confined pyrolysis experiments using gold capsules at heating rates of 20 °C/h and 2 °C/h on kerogen samples from two Permian lacustrine oil-prone source rocks (J23S3 and SS1S3) having hydrogen indices of 663 and 698 mg HC/g TOC, respectively. The kinetic properties for oil and gas generation vary substantially between these two source rocks. Assuming a burial heating rate of 5 °C/My, the temperature for 50% transformation ratio to oil is 132 °C for J23S3 and 168 °C for SS1S3. The maximum oil yields are about 604 and 770 mg/g TOC, while the maximum yields of total gaseous hydrocarbons are about 306 and 348 mg/g TOC for J23S3 and SS1S3, respectively. Gaseous hydrocarbons from the confined pyrolysis experiments include primary cracking components from kerogen and secondary cracking components from the generated oil. The secondary cracking gaseous hydrocarbons comprise up to 84.9% and 95.1% of the total, respectively, for the two source rocks in the highest temperature experiments. A practical method estimates the amount of gaseous hydrocarbons generated from these source rocks under geological conditions based on: (1) kinetic parameters for gas generation obtained from kerogen confined pyrolysis experiments in the present study, (2) the maximum yield of gaseous hydrocarbons from oil confined pyrolysis experiments from previous studies, and (3) the maximum amount of expelled oil. The maximum amounts of expelled oil range from 509–588 and 724–750 mg/g TOC with oil expulsion efficiencies in the ranges 84.3–97.4% and 94.0–97.4% for J23S3 and SS1S3, respectively, assuming that the amounts of retained oil range from 30–160 and 50–110 mg/g TOC for the two source rocks after oil expulsion based on the amounts of extracted bitumen. Consequently, the maximum yields of total gaseous hydrocarbons could be in the ranges 53.1–87.0 and 25.5–36.8 mg/g TOC, respectively, for J23S3 and SS1S3 in nature. Using the kinetic parameters for these two source rocks determined from pyrolysis experiments, oil and gas generation and expulsion were modeled for source rocks within the Lower Permian Fengcheng (P1f) and Middle Permian Lower Wuerhe formations (P2w) in the central area of the Mahu Depression, the source kitchen for most oilfields in the basin.

•Two Carboniferous source rocks differ in molecular and isotopic compositions.•Oils are mainly derived from the Lower Carboniferous source rocks.•Charging oil changed in facies and maturity during reservoir filling process.Carboniferous source rocks have been gaining increasing attention after the discovery of the Kelameili gasfield in the Eastern Junggar Basin in 2005. Two sets of source rocks within the Lower Carboniferous Dishuiquan Formation (C1d) and Upper Carboniferous Batamayineishan Formation (C2b), respectively, have been identified in this area. In this paper, clear differences between these two source rocks are demonstrated in molecular and carbon isotopic compositions. The C1d source rocks, in comparison with the C2b source rocks, have remarkably lower Pr/n-C17 ratio, higher Ts/(Ts + Tm) and C30 diahopane/(C30 diahopane + C30 hopane) ratios, lower concentration of C24 tetracyclic terpane relative to C23 and C26 tricyclic terpanes and higher gammacerane/C31 hopane ratio. δ13C values of individual n-alkanes decrease with carbon number for C1d source rocks while the opposite is true for C2b source rocks.Among the 10 oils collected from the studied area, four were generated exclusively from C1d source rocks while the others were mainly derived from C1d source rocks but contaminated by a small or trace amount of oil components which were derived from the C2b, Middle Permian Pingdiquan Formation (P2p) and Lower Jurassic source rocks.The free, adsorbed and inclusion oils from three oil-containing volcanic reservoir rocks within the C2b formation generally correlate with C1d source rocks based on molecular and carbon isotopic data. However, the three types of oil from the same reservoir rock vary significantly in molecular and carbon isotopic compositions, reflecting facies and maturity changes of charging oil during the reservoir filling.

•Coal, extracted coal and bitumen enriched coal were pyrolyzed.•Yields and compositions of bitumen, liquid n-alkanes and gases were determined.•Kinetic parameters for the generation and cracking of gas hydrocarbons were derived.Three sets of pyrolysis experiments were performed on extracted coal (Ro% 0.39), coal (initial bitumen 13.5 mg/g coal) and bitumen enriched coal (total bitumen 80.9 mg/g coal) at two heating rates of 2 °C/h and 20 °C/h in confined systems (gold capsules). For all three experiments, the yields of bitumen, Σn-C8+, aromatic components and ΣC2–5 at first increase and then decrease with increasing EASY%Ro and reach the highest values within the EASY%Ro ranges of 0.67–1.08, 1.07–1.19, 1.46–1.79 and 1.46–1.68, respectively. In contrast, C1/ΣC1–5 ratio at first decreases and then increases with EASY%Ro and reaches a minimum value in EASY%Ro range of 0.86–1.08, closely corresponding to the maximum values of the yields of bitumen and Σn-C8+. Methane yields increase consistently with EASY%Ro. Nearly half of the maximum yield of methane from kerogen was generated at EASY%Ro > 2.2. The differences in methane yields among the three experiments at the same thermal stress are relatively minor at EASY%Ro < 2.2, but are greater with thermal stress at EASY%Ro > 2.2. This demonstrates that the kerogen always retained relatively more hydrogen and hydrocarbon generative potential at the postmature stage of bitumen rich coal than the extracted coal or coal.The maximum yield of ethane is 20–25% higher in the bitumen rich coal experiment than the extracted coal or coal, while the maximum yields of C3, C4 and C5 in the former are double to triple those in the latter. This result demonstrates that the added bitumen in bitumen rich coal substantially increased the generation of these wet gases. However, the averaged values of activation energies (with the same frequency factors) for both the generation and cracking of individual wet gases are similar and do not show consistent trends among the three experiments. For all three experiments, activation energies for the generation and cracking of wet gases are significantly lower than those in previously published oil pyrolysis experiments with same frequency factors (Pan et al., 2012; Organic Geochemistry 45, 29–47). Methane δ13C values at the maximum temperature or EASY%Ro are close to those of initial wet gases, especially C3, implying that the major part of methane shared a common initial precursor with wet gases, i.e., free and bound liquid alkanes.

Carbon isotopic compositions were determined by GC–IRMS for individual n-alkanes in crude oils and the free, adsorbed and inclusion oils recovered by sequential extraction from reservoir rocks in the Tazhong Uplift and Tahe oilfield in the Tabei Uplift of Tarim Basin as well as extracts of the Cambrian–Ordovician source rocks in the basin. The variations of the δ13C values of individual n-alkanes among the 15 oils from the Tazhong Uplift and among the 15 oils from the Triassic and Carboniferous sandstone reservoirs and the 21 oils from the Ordovician carbonate reservoirs in the Tahe oilfield demonstrate that these marine oils are derived from two end member source rocks. The major proportion of these marine oils is derived from the type A source rocks with low δ13C values while a minor proportion is derived from the type B source rocks with high δ13C values. Type A source rocks are within either the Cambrian–Lower Ordovician or the Middle–Upper Ordovician strata (not drilled so far) while type B source rocks are within the Cambrian–Lower Ordovician strata, as found in boreholes TD2 and Fang 1. In addition, the three oils from the Cretaceous sandstone reservoirs in the Tahe oilfield with exceptionally high Pr/Ph ratio and δ13C values of individual n-alkanes are derived, or mainly derived, from the Triassic–Jurassic terrigenous source rocks located in Quka Depression.The difference of the δ13C values of individual n-alkanes among the free, adsorbed and inclusion oils in the reservoir rocks and corresponding crude oils reflects source variation during the reservoir filling process. In general, the initial oil charge is derived from the type B source rocks with high δ13C values while the later oil charge is derived from the type A source rocks with low δ13C values.The δ13C values of individual n-alkanes do not simply correlate with the biomarker parameters for the marine oils in the Tazhong Uplift and Tahe oilfield, suggesting that molecular parameters alone are not adequate for reliable oil-source correlation for high maturity oils with complex mixing.Highlights► GC–IRMS was performed for crude oils and components in source and reservoir rocks. ► The δ13C values show the marine oils are derived from two types of source rocks. ► The δ13C values for oil components in reservoir rocks reveal source variations. ► δ13C values do not correlate with biomarker parameters for mature oils.

Three sets of pyrolysis experiments were performed for oil alone, pyrobitumen alone and oil plus pyrobitumen at two heating rates of 2 °C/h and 20 °C/h in confined systems (gold capsules). The results of these experiments demonstrated that pyrobitumen significantly promoted the generation of methane while not only inhibiting the generation, but also accelerating the cracking of wet gases during oil cracking experiments in confined systems. Furthermore, the cracking rate of wet gases increases with pyrobitumen/oil ratios. As a result, C1/ΣC1–5 ratio is significantly higher in the experiment of oil plus pyrobitumen than oil alone at the same temperature conditions. Although the amount of methane increased, the weight of the total gaseous hydrocarbons decreased and the volume of the total gaseous hydrocarbons remained unchanged with the addition of pyrobitumen. This result can be ascribed to some oil and wet gas components being combined with the pyrobitumen phase and released later mainly as methane at higher temperatures and maturities. The activation energies for the generation and cracking of wet gases decrease with the carbon number and are relatively lower in the experiments of oil plus pyrobitumen than oil alone. The distribution ranges of the activation energies for the generation of wet gases also decrease with the carbon number.Highlights► Pyrobitumen promoted the generation of methane. ► Pyrobitumen accelerated the cracking of wet gases. ► Oil and wet gas components were combined into pyrobitumen phase.

Molecular data from a large set of source rock, crude oil and oil-containing reservoir rock samples from the Tarim Basin demonstrate multiple sources for the marine oils in the studied areas of this basin. Based on gammacerane/C31 hopane and C28/(C27 + C28 + C29) sterane ratios, three of the fifteen crude oils from the Tazhong Uplift correlate with Cambrian–Lower Ordovician source rocks, while the other crude oils from the Tazhong Uplift and all 39 crude oils from the Tahe oilfield in the Tabei Uplift correlate with Middle–Upper Ordovician source rocks. These two ratios further demonstrate that most of the free oils and nearly all of the adsorbed and inclusion oils in oil-containing reservoir rocks from the Tazhong Uplift correlate with Cambrian–Lower Ordovician source rocks, while the free and inclusion oils in oil-containing carbonates from the Tahe oilfield correlate mainly with Middle–Upper Ordovician source rocks. This result suggests that crude oils in the Tazhong Uplift are partly derived from the Cambrian–Lower Ordovician source rocks while those in the Ordovician carbonate reservoirs of Tahe oilfield are overwhelmingly derived from the Middle–Upper Ordovician source rocks.The scatter of C23 tricyclic terpane/(C23 tricyclic terpane + C30 17α,21β(H)-hopane) and C21/(C21 + ΣC29) sterane ratios for the free and inclusion oils from oil-containing carbonates in the Tahe oilfield possibly reflects the subtle organofacies variations in the source rocks, implying that the Ordovician reservoirs in this oilfield are near the major source kitchen. In contrast, the close and positive relationship between these two ratios for oil components in the oil-containing reservoir rocks from the Tazhong Uplift implies that they are far from the major source kitchen.Highlights► 3/15 Tazhong Uplift oils correlate with Cambrian–Lower Ordovician source rocks. ► 12/15 Tazhong and 39 Tabei oils correlate with Middle–Upper Ordovician source rocks. ► Free, adsorbed and inclusion oils have been recovered and analyzed by GC and GC–MS.

Three sets of pyrolysis experiments were performed for oil alone, oil plus montmorillonite and oil plus calcite at two heating rates of 2 °C/h and 20 °C/h in confined systems (gold capsules). The main observations can be listed as follows: (1) the ratios of i-C4/n-C4, i-C5/n-C5 and the amount of butanes (n-butane + i-butane) are significantly higher in the experiment for oil plus montmorillonite than oil alone and oil plus calcite, indicating the acidic catalysis by montmorillonite; (2) at low conversion values (<0.5 for methane generation), the formation rates of methane and total hydrocarbon gases in all the three experiments are very similar, demonstrating that neither montmorillonite nor calcite significantly influence the primary cracking of oil components (C6+) into gaseous hydrocarbons (C1–C5), while at high conversion values (>0.5 for methane generation), the formation rates of methane and the total hydrocarbon gases in the oil plus calcite experiment are relatively lower than the other two experiments, demonstrating that calcite hindered the secondary cracking of wet gases (C2–C5) into methane; (3) both montmorillonite and calcite greatly reduce the carbon isotope fractionation during methane formation from oil cracking, resulting in substantially higher methane δ13C values in the oil plus montmorillonite or calcite experiments than for oil alone. Based on the kinetic parameters determined from the oil cracking experiments, the predicted temperatures and vitrinite reflectance values (% Easy Ro) for the formation of methane and the total gaseous hydrocarbons at 10% conversion are 190–192 °C and 184–187 °C, and 1.90–1.93% and 1.80–1.86%, respectively at the heating rate 1 °C/my, demonstrating that oils are very thermally stable in sedimentary basins.

This paper documents the distribution and maturation behavior of hopanoids and steranes released from kerogen (Estonian Kukersite) during pyrolysis experiments, performed in confined system (gold capsule) in presence and absence of water and various minerals, kaolinite, montmorillonite, calcite and dolomite respectively, at a fixed pressure of 50 MPa and temperature ranging from 240–320 °C. The abundances of hopenes and 17β(H)21β(H)-hopanes relative to stable 17α(H)21β(H)-hopanes, as well as calculated maturity parameters obtained from steranes and homohopanes are significantly different for the studied kerogen mixed with different minerals, and the presence or absence of water. The results of our experiments show that the maturation rates of hopanoids and steranes increase with mineral acidity but decrease with the addition of water. Furthermore, the stabilities of hopenes relative to 17β(H)21β(H)-hopanes also vary significantly at a same temperature among the six runs. Hopenes are more sensitive to the addition of excessive amount of water and pH value of minerals than are 17β(H)21β(H)-hopanes.

The free, adsorbed and inclusion oils were recovered by sequential extraction from eleven oil and tar containing reservoir rocks in the Tazhong Uplift of Tarim Basin. The results of gas chromatography (GC) and GC–mass spectrometry analyses of these oil components and seven crude oils collected from this region reveal multiple oil charges derived from different source rocks for these oil reservoirs. The initially charged oils show strong predominance of even over odd n-alkanes in the range n-C12 to n-C20 and have ordinary maturities, while the later charged oils do not exhibit any predominance of n-alkanes and have high maturities. The adsorbed and inclusion oils of the reservoir rocks generally have high relative concentrations of gammacerane and C28 steranes, similar to the Cambrian-Lower Ordovician source rocks. In contrast, the free oils of these reservoir rocks generally have low relative concentrations of gammacerane and C28 steranes, similar to the Middle-Upper Ordovician source rocks. There are two interpretations of this result: (1) the initially charged oils are derived from the Cambrian-Lower Ordovician source rocks while the later charged oils are derived from the Middle-Upper Ordovician source rocks; and (2) both the initially and later charged oils are mainly derived from the Cambrian-Lower Ordovician source rocks but the later charged oils are contaminated by the oil components from the Silurian tar sandstones and the Middle-Upper Ordovician source rocks.

The confined pyrolysis experiments of Kukersite kerogen in the presence and absence of minerals and water revealed the effects of mineral acidity and water/OC ratio on the conversion of kerogen into petroleum. The amount of bitumen and liquid hydrocarbons demonstrate that organic maturation rate increase with mineral acidity even in the presence of a large amount of water (water/OC 7–10). Organic maturation rate appeared unaffected with the addition of a small amount of water (water/OC 1.5), but it can be retarded with the addition of a large amount of water (water/OC 7–10) in confined pyrolysis experiments. The relative abundances of n-alkanes decrease whereas those of isoalkanes, cycloalkanes and light alkylbenzenes increase with both the mineral acidity and water/OC ratio. The relative abundances of naphalene, methylnaphalenes, phenanthrene and methylphenanthrenes also increase with mineral acidity but exhibit no clear variation trend with water/OC ratio.

Pyrolysis experiments on kerogen (Estonian Kukersite) were conducted in a confined system (gold capsules) in the presence and absence of water and various minerals, i.e., kaolinite, montmorillonite, calcite, and dolomite, respectively, at a fixed pressure of 50 MPa and in the temperature range 240–400 °C. For the four experiments in the presence of minerals and a large amount of deionized water (OC/mineral/water 1:24:7–10), the ratios of isobutane/n-butane and isopentane/n-pentane generally increase with temperature and mineral acidity. As to the two experiments for kerogen alone and kerogen plus a small amount of water (OC/water 1:1.5), these two ratios are relatively high at low temperature (280–320 °C) and substantially low at high temperature (320–400 °C) in comparison with the experiments in the presence of minerals and a large amount of deionized water. The ratios of ethene/ethane and propene/propane generally decrease with increasing temperature. At the same temperature, these two ratios increase with an increasing amount of water and decrease with increasing mineral acidity. Pyrolysis experiments on this Kukersite kerogen with various OC/water ratios (0–15) further demonstrated that the ratios of ethene/ethane, propene/propane, isobutane/n-butane, and isopentane/n-pentane increased with increasing water/OC ratio. In addition, the amount of the gas hydrocarbons varied significantly with water/OC ratio, i.e., from 83.20 to 109.70 mg/g of OC at 350 °C and from 271.50 to 340.07 mg/g of OC at 450 °C, with the water/OC ratio increasing from 0 to 15. The amount of CO2 produced also increases substantially and consistently with that of gas hydrocarbons with water/OC ratio. The amount of oxygen in the generated CO2 exceeds the oxygen in the initial kerogen in the experiments with water/OC ratios of 10 and 14.5 at 450 °C, indicating that water derived hydrogen and oxygen have been incorporated into gas hydrocarbons and CO2.

The 22S/(22S + 22R) ratios for C31–C35 homohopanes and the 20S/(20S + 20R) ratio for C29 steranes were measured by gas chromatography–mass spectrometry (GC–MS) on six Oligocene saline lacustrine rock samples from a borehole located in the western Qaidam Basin, northwest China. These ratios vary significantly and irregularly with burial depth from 2831 m to 3054 m around the threshold of the oil generation window. In addition, 22S/(22S + 22R) ratios also vary substantially among different homologs within the same sample, generally decreasing from C31 to C35 homohopanes. The distribution patterns of homohopanes for the six samples are unusual, such as, C31 < C32 > C33 > C34 < C35, or C31 > C32 > C33 < C34 < C35, or C31 < C32 > C33 < C34 < C35. All of these observations can be mainly ascribed to the release of bound hopanes and steranes from kerogen and other macromolecules.The 22S/(22S + 22R) ratios of C31, C32 and C33 homohopanes decreased, while that of C34 homohopanes increased for two samples, YHS1 and YHS6, after pyrolysis at low temperatures (180–270 °C). A major reversal of 20S/(20S + 20R) ratio for C29 steranes was observed at 240 °C for sample YHS1, but at 270 °C for sample YHS6. The distributions of homohopanes for these two samples after pyrolysis changed from their original patterns toward the normal pattern C31 > C32 > C33 > C34 > C35. These results reflect the influences of thermal degradation and direct isomerization of the free biomarkers and the release of bound biomarkers from kerogen and other macromolecules during pyrolysis.

Crude oils in the Daerqi oilfield vary greatly in viscosities, including normal, viscous and highly viscous oils. They are also dramatically different in thermal maturity, from immature to mature based on biomarker parameters. According to bulk and molecular geochemical characteristics, crude oils can be classified into three groups in this oilfield. Group I oils are mature and derived from the deeply buried and relatively old source rocks within the Tengger Formation and the second member of the Arshan Formation of early Cretaceous age. Group II oils are immature to marginally mature and derived from the relatively young source rocks that experienced shallow burial within the first member of the Duhongmu Formation of earlier Cretaceous age. Group III oils are mixtures of group I and group II oils, with dominance of the group I oils (>70%). The viscosity is low for the non-biodegraded group I and group III oils (7.1–24 mPa s) but very high for the non-biodegraded group II oils (e.g., 433,104 mPa s for the representative oil Da12O1). The group III oils are similar to the group I oils in gross properties (e.g., gross composition and viscosity), but are similar to group II oils in terms of their molecular maturity parameters. The oil reservoirs are currently at a shallow depth (<800 m), and some oils are heavily biodegraded up to level 4 on the [Peters, K.E., Moldowan, J.M., 1993. The Biomarker Guide: Interpreting Molecular Fossils in Petroleum and Ancient Sediments. Englewood Cliffs, Prentice-Hall, NJ] scale in this oilfield. A peculiar phenomenon is that some of the group I and group III oils have been heavily biodegraded, whereas the group II oils, interbedded with the biodegraded group I and/or group III oils within a narrow interval in the same wells, are not altered by biodegradation. This is possibly due to the low diffusion coefficient of hydrocarbons and isolation to meteoric water percolation for the group II oil columns.

The free oil (first Soxhlet extract) and adsorbed oil (Soxhlet extract after the removal of minerals) obtained from the clay minerals in the <2 μm size fraction as separated from eight hydrocarbon reservoir sandstone samples, and oil inclusions obtained from the grains of seven of these eight samples were studied via GC, GC–MS and elemental analyses. The free oil is dominated by saturated hydrocarbons (61.4–87.5%) with a low content of resins and asphaltenes (6.0–22.0% in total) while the adsorbed oil is dominated by resins and asphaltenes (84.8–98.5% in total) with a low content of saturated hydrocarbons (0.6–9.5%). The inclusion oil is similar to the adsorbed oil in gross composition, but contains relatively more saturated hydrocarbons (16.87–31.88%) and less resins and asphaltenes (62.30–78.01% in total) as compared to the latter.Although the amounts of both free and adsorbed oils per gram of clay minerals varies substantially, the residual organic carbon content in the clay minerals of the eight samples, after the free oil extraction, is in a narrow range between 0.537% and 1.614%. From the decrease of the percentage of the extractable to the total of this residual organic matter of the clay minerals with burial depth it can be inferred that polymerization of the adsorbed polar components occurs with the increase of the reservoir temperature.The terpane and sterane compositions indicate that the oil adsorbed onto the clay surfaces appears to be more representative of the initial oil charging the reservoir than do the oil inclusions. This phenomenon could possibly demonstrate that the first oil charge preferentially interacts with the clay minerals occurring in the pores and as coatings around the grains. Although the variation of biomarker parameters between the free and adsorbed oils could be ascribed to the compositional changes of oil charges during the filling process and/or the differential maturation behaviors of these two types of oils after oil filling, the fractionation of the ratios of αββ/(αββ + ααα) regular steranes and C27 diasteranes/C27 regular steranes between these two types of oils can be unambiguously ascribed to the selective adsorption effects by the polar components and the active clay surfaces during the interaction of oil phase and clay surfaces.

Free oils and inclusion oils (oil-bearing fluid inclusions) of 12 samples collected from the sandstone reservoir formations in the central, eastern and northern areas of the Junggar Basin, northwest China, were analyzed by GC and GC-MS. Analytical results indicate very similar biomarker distributions within each of the free oils and their associated inclusion oils in the two samples collected, respectively, from the northwestern and eastern border of the Junggar Basin. The free oil and inclusion oil of sample MD1-1, collected from the northwestern border, correlate well with the Permian source rock of the Fencheng Formation, while those of sample DN1-1 from the eastern border correlate with the Permian source rock of the Pingdiquan Formation. In contrast, in the central area, the free and inclusion oils vary significantly in most cases, which suggests variations of sources for oil charges during the filling process. These data, and the correlation between the free and inclusion oils, are consistent with the field and seismic data, which show that in areas where samples MD1-1 and DN1-1 are located, only one available source rock exists, while in the central area, multiple source rocks are present.

The parameter S1 + S2 (genetic potential) of Rock-Eval analysis is widely used as an evaluation of the genetic potential for the source rocks. Oligocene–Miocene saline lacustrine source rocks in the western Qaidam basin have low total organic C contents (TOC), most around 0.5% with a few exceptions >1.0%. Mineral matrix effects are substantial for source rocks with low TOC, resulting in relatively low S1 and S2 peaks. Based on the results of confined pyrolyses (sealed Au capsules) on 6 Oligocene–Miocene source rocks from the western Qaidam basin, with TOC ranging between 0.48% and 2.22%, the relationship between the S1 + S2 parameter and the maximum amount of extracted bitumen or saturated and aromatic hydrocarbons (SA) after the confined pyrolysis has been established as follows: bitumen (mg/g rock) = 1.4924 × (S1 + S2) + 0.3201 (r = 0.987), or SA (saturates + aromatics) (mg/g rock) = 0.7083 × (S1 + S2) + 0.4045 (r = 0.992). Based on these formulas, the amounts of hydrocarbons generated from source rocks can be reasonably estimated. The typical crude oils with low biomarker maturities in this region appear substantially different to the pyrolysates of these six rocks at 180–300 °C but comparable to the pyrolysates at 320 °C and higher temperatures based on molecular parameters. This result, in combination with the physical and gross compositions of the crude oils, suggests that the majority of these crude oils were generated from the source rocks during the main oil-generative stage, possibly at a maturity higher than Ro 0.74%.

•Confined pyrolysis experiments on oil alone, coal alone and coal plus oil were performed.•Oil retards the generation of gas hydrocarbons from coal cracking.•Coal accelerates oil cracking into gas hydrocarbons.Isothermal pyrolysis experiments were performed for coal alone, oil alone and coal plus oil with oil/coal ratios ranging from 0.0065 to 0.1995 at 305 °C and 50 MPa for 72 h in confined systems (gold capsules). The results of these experiments reveal the interaction between coal and oil, demonstrating that oil retards the generation of gas hydrocarbons from coal cracking while coal accelerates oil cracking into gas hydrocarbons. The yields of gas hydrocarbons vary greater with oil/coal ratio in the experiments of coal B plus oil than coal A plus oil because coal A has a higher HI value than does coal B. Oil cracking rate could increase by up to 10 or even higher times in the experiments of coal plus oil compared with oil alone, deduced from the yields and chemical compositions of gas hydrocarbons. This result suggests that gas hydrocarbons, especially wet gases were largely generated from the cracking of oil or extractable bitumen in the experiments of coal plus oil with oil/coal ratio higher than 0.1.