β-Carotene, the precursor of β-carotane, is commonly rich in brackish sediments and would become unstable theoretically under the exposure to high temperatures, bright light conditions, and acidic or ...oxdizing environments. However, the specific process and mechanism of the absence of such compounds are still not clear sufficiently. To fill the knowledge gap, in this study we explore the origin of the absence of β-carotane in a 50-m-thick section of the Middle Permian Lucaogou Formation in the Jimusar Sag, Junggar Basin, northwest China, based on a combined mineralogical, petrographic, organic and inorganic geochemical study. Biomarker analyses indicate that the β-carotane-free section was deposited in a brackish, reducing, and semi-deep lacustrine environment. Hydrothermal fluid effects during sediment deposition are inferred to have caused the breakdown of β-carotene. The hydrothermal (<100 °C) effects are evidenced by mineralogy and geochemistry, e.g., the hydrothermal-indicative minerals (reedmergnerit, tuff and pyrite), high Fe/Ti and low Al/(Al + Fe) ratios, rare earth elements (REEs) distribution. Associated biomarker variations were found, e.g., low i-alkanes/n-alkanes, high C24Tetracyclic/C26Tricyclic terpanes, high (C19 + C20)/(C21 + C23) tricyclic terpanes, high C29/C30 hopanes, and very low gammacerane/C30 hopane ratios. Our data suggest that hydrothermal fluids can prevent the preservation of β-carotene, and the absence of β-carotane indicates a period of hydrothermal activity during deposition of the Lucaogou Formation in a 50-meter-thick sequence.
•β-Carotanes were found to be absent in a brackish lacustrine sequence.•Hydrothermal fluids have caused the breakdown of β-carotene.•Anomalously low abundance of isomerization alkanes and high C24Tet/C26 TT ratios were also found.•Hydrothermal activity was present in the Permian Lucaogou Formation, Junggar Basin.•Absence of β-carotane can be used as a proxy for hydrothermal activity.
•C1/ΣC1-5 ratios negatively correlate to oil yields in confined pyrolysis.•Wet gas incorporation to kerogen leads to higher C1/ΣC1-5 ratios.•Petroleum formation and evolution can be a recycling ...process.
The formation mechanism for thermogenic gas remains unresolved. Disputes are focused on: (1) stability barrier for decomposition of oil to gas and wet gas to methane, and (2) inconsistence in dryness ratio (C1/ΣC1–5) between gases produced in pyrolysis experiments and in natural reservoirs. Here, we demonstrate the variation trend of dryness ratio (C1/ΣC1–5) with temperatures and thermal stress levels, and the correlation of dryness ratios with the yields of liquid components (ΣC8+) in confined pyrolysis experiments (gold capsules) of twenty coals. At both heating rates of 2 and 20 °C/h, dryness ratios of gaseous hydrocarbons at first decrease, and then increase with increasing temperatures and thermal stress levels. Dryness ratios of produced gases can be very high in the range of 66.3–95.7 wt% at initial temperature about 334 °C and heating rate of 20 °C/h, corresponding to EASY%Ro 0.56. We suggest that these gases are not the original products released from kerogen, but have been altered via wet gas incorporation to kerogen. Larger oil molecules (C8+) are more competitive in incorporating to kerogen compared with wet gases, and therefore, prohibit wet gas incorporation, leading to the observed trend of gas dryness ratios with increasing temperature and maturity and the negative correlation between dryness ratios and the yields of liquid components (ΣC8+). The conflicting results between the yields and carbon isotopes of wet gases produced in the isothermal confined pyrolysis experiments for coal plus oil can be well interpreted using the reaction mechanism that wet gases incorporate to kerogen while oil components retard this incorporation. Once free oil and wet gas molecules are reincorporated to kerogen, the bound molecules can easily decompose to smaller molecules due to substantial reduction of activation energy for carbon-carbon bond rupture. Petroleum formation from kerogen can be a recycling process: kerogen first releases oil compounds, and then free molecules reincorporate to kerogen and further decompose to smaller molecules, and finally to methane.
Oil and condensate reservoirs frequently experienced later gas charging and cap gas leakage. The influences of these two processes on diamondoid concentrations and compositions are not well ...documented. To investigate these issues, quantitative GC, GC-MS and GC-IRMS analyses were performed on 24 condensates from the Kekeya Field of gas condensate in the Southwestern Depression of the Tarim Basin, northwestern China. Only normal oils filled the reservoirs of this field prior to gas charging. Based on biomarker concentrations and carbon isotopic composition of individual n-alkanes, these oils were derived from multiple source rocks within the Permian and Middle–Lower Jurassic strata within the early to late window of oil generation. Diamondoid concentrations and compositions of condensates were mainly controlled by the gas that subsequently charged the reservoirs and the extents of cap gas leakage. Two deeper condensates KS101C2 and KS101C3 at 6651–6835 m have extremely high concentrations of 4- + 3-methyldiamantanes (4 + 3MD) in the range of 2523–4296 ppm and very low ratios of adamantane/diamantane (A/D) and methyladamantanes/methyldiamantanes (MAs/MDs) in the ranges of 0.10–0.11 and 0.28–0.33, respectively, demonstrating that these reservoirs were charged by the primary gas with high diamondoid concentration that was generated from very deeply buried source rocks at post mature stage in combination with extensive leakage of the cap gas (the secondary gas). The shallower condensate K2C2 at 3319–3326 m has a moderate 4 + 3MD concentration of 18 ppm and very low ratios of A/D and MAs/MDs of 0.00 and 0.19, respectively, demonstrating that this reservoir was charged by the secondary gas in combination with extensive leakage of the cap gas (the third-generation gas). The shallower condensate KX3C at 3765–3820 m has a lower 4 + 3MD concentration of 9 ppm but very high ratios of A/D and MAs/MDs of 8.60 and 16.73, respectively, demonstrating that this reservoir was charged by the third-generation gas with or without minor cap gas leakage. The other twenty condensates have 4 + 3MD concentrations in the range of 7–23 ppm and ratios of A/D and MAs/MDs in the ranges of 0.60–5.29 and 2.18–12.18, respectively, demonstrating that these reservoirs were charged by the secondary or/and third-generation gases with different extents of cap gas leakage. Furthermore, cap gas leakage influenced alkyladamantane ratios of MAI, DMAI-1, TMAI-1, TMAI-2 and EAI but not the alkyldiamantane ratios of MDI, DMDI-1 and DMDI-2 for maturity and source.
•Kekeya field reservoirs experienced multiple oil/gas charging episodes.•Primary gas charging led to higher 4 + 3MD concentration.•Secondary and third-generation gas charging led to lower 4 + 3MD concentration.•Cap gas leakage led to lower ratios of A/D and MAs/MDs.•Cap gas leakage influenced alkyladamantane ratios but not alkyldiamantane ratios.
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-C
4/
n-C
4,
i-C
5/
n-C
5 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 (C
6+) into gaseous hydrocarbons (C
1–C
5), 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 (C
2–C
5) into methane; (3) both montmorillonite and calcite greatly reduce the carbon isotope fractionation during methane formation from oil cracking, resulting in substantially higher methane δ
13C 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
R
o) 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.
•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).
•Maturity of Mahu oils was assessed by biomarkers, light hydrocarbons and diamondoids.•Biomarkers entered the reservoirs along with the initial oil charge.•Light hydrocarbons and diamondoids entered ...the reservoirs with the late gas charge.•Hydrocarbon compositions indicate large amounts of gas charging of the reservoirs.•Low gas to oil ratios for the reservoirs can be mainly ascribed to gas leakage.
It remains disputed why a large amount of oil but only a limited amount of gas has been discovered in the northwestern Junggar Basin of China, although most source rocks are post-mature. Quantitative GC, GC–MS and GC–IRMS analyses were performed on 92 oils from this region to investigate gas charging and leakage of the petroleum reservoirs in the Mahu sag and nearby areas of the northwestern portion of the Junggar Basin. The 92 oils have moderate to high concentrations of C30 hopane (18–3840 ppm) and ΣC29 regular steranes (38–6100 ppm), demonstrating that these oils have normal maturities, within the oil generation window. However, these oils have high heptane and isoheptane values in the ranges of 31.1–52.2 and 0.82–7.74, respectively, and diamondoid (4- + 3-methyldiamantanes) concentrations over a wide range of 1.07–22.0 ppm. These results demonstrate that the reservoirs for all the studied oils have multiple charging episodes: terpanes and steranes entered the reservoirs along with the initial oil charges from source rocks within the oil generation window while light hydrocarbons and diamondoids mainly entered the reservoirs along with the late gas and condensate charging from deep post-mature source rocks. The difference between the maximum and minimum 4- + 3-methyldiamantane (4 + 3MD) concentrations (Cmax – Cmin)/Cmax is equal to 0.95. A higher ratio of (Cmax – Cmin)/Cmax (> 0.50) can be indicative of late gas and condensate charging to the reservoirs. Lower gas/oil ratios (GOR) for the reservoirs of the studied oils can be mainly ascribed to gas leakage.
•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 13.5mg/g coal) and bitumen enriched coal (total bitumen 80.9mg/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.
► Pyrobitumen promoted the generation of methane. ► Pyrobitumen accelerated the cracking of wet gases. ► Oil and wet gas components were combined into pyrobitumen phase.
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.
Quantitative GC-MS analysis was performed on 138 oils from the cratonic regions of the Tarim Basin, northwestern China. Crossplots of (1) biomarker concentrations versus maturity ratios, (2) ...diamondoid concentrations versus sterane concentrations, (3) ratios of (Pr + Ph)/(n-C17+n-C18), and (4) Σn-C15–35/Σn-C9–14, were constructed and compared with oil densities, GOR and gas dryness. The results clearly show oil mixing resulting from a very complex charging history. At least four oil/gas charging episodes can be identified. One episode is represented by oils which have relatively high biomarker concentrations with maturity ratios suggesting an early to middle oil window source. There is second charge resulting in intermediate to low biomarker concentrations in many of the oils indicating a charge generated in the mid-to late-oil window. The third charge can be seen in oils in which biomarkers are absent indicating that they were sourced at late oil to wet gas levels of thermal maturity. Finally, the fourth charge is indicated by the high diamondoid concentrations in virtually every oil in this study. This charge was generated from very deeply buried source rocks at dry gas levels of thermal maturity where extensive oil to gas cracking has taken place. The fact that the oils show varying concentrations of biomarkers from low to high and yet similar low-maturity biomarker ratios suggests oil mixing to various extents, in which the biomarkers are predominantly derived from the least mature source, but they are differentially diluted by higher-maturity liquids poor in biomarkers. Furthermore, the deep charge represented by the high diamondoids concentrations is present in virtually every sample. Our results suggest that the oils in this study are all mixtures containing varying percentages of components derived from these four charges.
•Crossplots of biomarker concentration versus maturity ratio were introduced.•Tazhong oil reservoirs formed by four oil/gas charging episodes.•Tabei oil reservoirs formed mainly by the earlier two oil charging episodes.•Diamondoids mainly entered the reservoirs at the late gas charge.
