Organic‐geochemical characteristics of the Miocene Lycian Basin,western Taurides,Turkey

In the Lycian Basin (SW Turkey), the Miocene Karabay?r and Karaku?tepe formations consist of algal limestone, conglomerate, sandstone, shale and limestone. Total organic carbon (TOC) analysis of the Miocene units show that these formations are poor in organic matter. TOC values are generally between 0.02 and 0.51%, but reach 3.47% in the Karabay?r Formation. Hydrogen indices (HI) are mostly below 600 mgHC/gTOC, increasing to 1200 mgHC/gTOC in the Karabay?r Formation. S₂ vs. TOC diagrams are used to evaluate the sedimentary environments and hydrocarbon potential of the Lower–Middle Miocene sediments (the Isparta, Bucak and Korkuteli‐Elmal? areas). The organic material contains about 63 (type I), 35 (type II) and 29 (type II/III) pyrolysable hydrocarbons, respectively. The dominant organic matter is type II kerogens, and hydrocarbon generating potential is quite low. A positive x‐intercept has been calculated in analysed samples according to S₂ vs. TOC diagrams; this value shows a rock‐matrix effect. Clay is the main agent of adsorption. Biomarker characteristics also verify these results. Isoprenoid rates are Pr/Ph: 2, Pr/n‐C17: 1.9, and Pr/n‐C18: 0.5, and a high Pr/Ph ratio (pristane/phytane) indicates an oxic environment; the terpane C29 NH/C30 H ratio is >1 for the Karabay?r Formation, and this value indicates a carbonate lithology. On the other hand, the C25 NH/C30 H ratio is <1 for the Karaku?tepe Formation; this indicates that the hydrocarbons were derived from terrestrial organic matter. According to m/z 191 mass fragmentograms, the Miocene units contain oleanane, indicating a Tertiary age. The abundance of sterane C29>C28>C27 shows that the kerogens formed from algal organic matter.     

The petroleum generation potential and effective oil window of humic coals related to coal composition and age

A worldwide data set of more than 500 humic coals from the major coal-forming geological periods has been used to analyse the evolution in the remaining (Hydrogen Index, HI) and total (Quality Index, QI) generation potentials with increasing thermal maturity and the ‘effective oil window’ (‘oil expulsion window’). All samples describe HI and QI bands that are broad at low maturities and that gradually narrow with increasing maturity. The oil generation potential is completely exhausted at a vitrinite reflectance of 2.0–2.2%R_o or T_max of 500–510 °C. The initial large variation in the generation potential is related to the original depositional conditions, particularly the degree of marine influence and the formation of hydrogen-enriched vitrinite, as suggested by increased sulphur and hydrogen contents. During initial thermal maturation the HI increases to a maximum value, HI_max. Similarly, QI increases to a maximum value, QI_max. This increase in HI and QI is related to the formation of an additional generation potential in the coal structure. The decline in QI with further maturation is indicating onset of initial oil expulsion, which precedes efficient expulsion. Liquid petroleum generation from humic coals is thus a complex, three-phase process: (i) onset of petroleum generation, (ii) petroleum build-up in the coal, and (iii) initial oil expulsion followed by efficient oil expulsion (corresponding to the effective oil window). Efficient oil expulsion is indicated by a decline in the Bitumen Index (BI) when plotted against vitrinite reflectance or T_max. This means that in humic coals the vitrinite reflectance or T_max values at which onset of petroleum generation occurs cannot be used to establish the start of the effective oil window. The start of the effective oil window occurs within the vitrinite reflectance range 0.85–1.05%R_o or T_max range 440–455 °C and the oil window extends to 1.5–2.0%R_o or 470–510 °C. For general use, an effective oil window is proposed to occur from 0.85 to 1.7%R_o or from 440 to 490 °C. Specific ranges for HI_max and the effective oil window can be defined for Cenozoic, Jurassic, Permian, and Carboniferous coals. Cenozoic coals reach the highest HI_max values (220–370 mg HC/g TOC), and for the most oil-prone Cenozoic coals the effective oil window may possibly range from 0.65 to 2.0%R_o or 430 to 510 °C. In contrast, the most oil-prone Jurassic, Permian and Carboniferous coals reach the expulsion threshold at a vitrinite reflectance of 0.85–0.9%R_o or T_max of 440–445 °C.     

Changes in bulk properties and molecular compositions within New Zealand Coal Band solvent extracts from early diagenetic to catagenetic maturity levels

The bulk properties and bitumen molecular compositions of a rank-series of 38 humic coals from the New Zealand Coal Band (Cretaceous–Cenozoic) have been analysed to investigate early maturation processes affecting coaly organic matter through diagenesis to moderate catagenesis (Rank(S_r) 0.0–11.8, R_o 0.23–0.81%). The samples comprise a relatively restricted range of vitrinite rich coal types formed largely from higher land plant material under relatively oxic conditions, but with a significant contribution from microbial biomass. With increasing rank, total organic carbon contents show a general increase, whereas moisture and asphaltene contents decrease. Bitumen yields also decrease through the stages of diagenesis and early catagenesis (Rank(S_r) < 9, R_o < 0.55%), indicating partial loss of initial bitumen during early maturation. Thermal generation of hydrocarbons begins slowly at Rank(S_r)  5–6 (R_o  0.40%) as indicated by the constant occurrence and gradual increase of isoprenoids (e.g., pristane and phytane) and hopanoids in their more mature αβ configuration. This early phase of catagenesis, not previously recognised in New Zealand coals, is followed at Rank(S_r)  9 (R_o  0.55%) by the main catagenesis phase characterised by a more rapid increase in the generation of hydrocarbons, including total n-alkanes, isoprenoids and αβ-hopanes. Changes in the maturity of New Zealand coals can be traced by the Carbon Preference Index and several hopane maturity parameters, including 22S/(22S + 22R), αβ/(αβ + βα) and ββ/(αβ + βα + ββ).     

Guidelines for assessing the petroleum potential of coaly source rocks using Rock-Eval pyrolysis

Coaly source rocks are sufficiently different from marine and lacustrine source rocks in their organic matter characteristics to warrant separate guidelines for their assessment using Rock-Eval pyrolysis. The rank threshold for oil generation is indicated by the increase in BI (S1/TOC) at Rank(S_r)9–10 (T_max 420–430 °C, R_o 0.55–0.6%), and the threshold for oil expulsion is indicated by the peak in QI ([S1+S2]/TOC) at Rank(S_r)11–12.5 (T_max 430–440 °C, R_o 0.65–0.85%). The pronounced rank-related increase in HI (S2/TOC) prior to oil expulsion renders the use of immature samples inappropriate for source rock characterisation. A more realistic indication of the petroleum generative potential and oil expulsion efficiency of coaly source rocks can be gained from samples near the onset of expulsion. Alternatively, effective HI′ values (i.e. HIs near the onset of expulsion) can be estimated by translating the measured HIs of immature samples along the maturation pathway defined by the New Zealand (or other defined) Coal Band. Coaly source rocks comprise a continuum of coaly lithologies, including coals, shaly coals and coaly mudstones. Determination of the total genetic potential of coaly source rock sequences is best made using lithology-based samples near the onset of expulsion.     

Organic geochemistry of the Vindhyan sediments: Implications for hydrocarbons

The organic geochemical methods of hydrocarbon prospecting involve the characterization of sedimentary organic matter in terms of its abundance, source and thermal maturity, which are essential prerequisites for a hydrocarbon source rock. In the present study, evaluation of organic matter in the outcrop shale samples from the Semri and Kaimur Groups of Vindhyan basin was carried out using Rock Eval pyrolysis. Also, the adsorbed low molecular weight hydrocarbons, methane, ethane, propane and butane, were investigated in the near surface soils to infer the generation of hydrocarbons in the Vindhyan basin. The Total Organic Carbon (TOC) content in shales ranges between 0.04% and 1.43%. The S₁ (thermally liberated free hydrocarbons) values range between 0.01–0.09 mgHC/gRock (milligram hydrocarbon per gram of rock sample), whereas the S₂ (hydrocarbons from cracking of kerogen) show the values between 0.01 and 0.14 mgHC/gRock. Based on the T_max (temperature at highest yield of S₂) and the hydrogen index (HI) correlations, the organic matter is characterized by Type III kerogen. The adsorbed soil gas, CH₄ (C₁), C₂H₆ (C₂), C₃H₈ (C₃) and nC₄H₁₀, (nC4), concentrations measured in the soil samples from the eastern part of Vindhyan basin (Son Valley) vary from 0 to 186 ppb, 0 to 4 ppb, 0 to 5 ppb, and 0 to 1 ppb, respectively. The stable carbon isotope values for the desorbed methane (δ¹³C₁) and ethane (δ¹³C₂) range between −45.7‰ to −25.2‰ and −35.3‰ to −20.19‰ (VPDB), respectively suggesting a thermogenic source for these hydrocarbons. High concentrations of thermogenic hydrocarbons are characteristic of areas around Sagar, Narsinghpur, Katni and Satna in the Son Valley. The light hydrocarbon concentrations (C₁–C₄) in near surface soils of the western Vindhyan basin around Chambal Valley have been reported to vary between 1–2547 ppb, 1–558 ppb, 1–181 ppb, 1–37 ppb and 1–32 ppb, respectively with high concentrations around Baran-Jhalawar-Bhanpur-Garot regions (Kumar et al., 2006). The light gaseous hydrocarbon anomalies are coincident with the wrench faults (Kota – Dholpur, Ratlam – Shivpuri, Kannod – Damoh, Son Banspur – Rewa wrench) in the Vindhyan basin, which may provide conducive pathways for the migration of the hydrocarbons towards the near surface soils.     

A study of the kinetic parameters of individual macerals from Upper Permian coals in South China via open-system pyrolysis

A unique Upper Permian coal, Leping coal, is widely distributed in South China. The coal samples studied in the paper were collected from two mines in the Shuicheng coalfield of Guizhou Province, southwest China. The geochemical works including coal petrography, maceral content, Rock–Eval pyrolysis, and kinetic modelling of hydrocarbon-generating have been carried out on whole coal and individual macerals. The higher contents of volatile matter, elemental hydrogen, and tar yield, and the high hydrocarbon generation potential of the Leping coals are attributed to their high content of “barkinite”, a special liptinite maceral.The hydrocarbon generation potential of “barkinite” (S₂=287 mg/g, hydrogen index (HI)=491 mg/g TOC) is greater than that of vitrinite (S₂=180 mg/g, HI=249 mg/g TOC), and much higher than that of fusinite (S₂=24 mg/g, HI=35 mg/g TOC). At the same experimental conditions, “barkinite” has a higher threshold and a narrower “oil window” than those of vitrinite and fusinite, and consequently, can generate more hydrocarbons in higher coalification temperature and shorter geological duration. Data from the activation energy distributions indicate that “barkinite” has a more homogenous chemical structure than that of vitrinite and fusinite. The above-mentioned characteristics are extremely important for exploring hydrocarbon derived from the Leping coals in South China.     

Confined pyrolysis of Tertiary lacustrine source rocks in the Western Qaidam Basin,Northwest China: Implications for generative potential and oil maturity evaluation

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 R_o 0.74%.     

Isotopic and molecular composition of coal-bed gas in the Amasra region (Zonguldak basin—western Black Sea)

Previous studies on the coal-bed methane potential of the Zonguldak basin have indicated that the gases are thermogenic and sourced by the coal-bearing Carboniferous units. In this earlier work, the origin of coal-bed gas was only defined according to the molecular composition of gases and to organic geochemical properties of the respective source rocks, since data on isotopic composition of gases were not available. Furthermore, in the western Black Sea region there also exist other source rocks, which may have contributed to the coal-bed gas accumulations. The aim of this study is to determine the origin of coal-bed gas and to try a gas-source rock correlation. For this purpose, the molecular and isotopic compositions of 13 headspace gases from coals and adjacent sediments of two wells in the Amasra region have been analyzed. Total organic carbon (TOC) measurements and Rock-Eval pyrolysis were performed in order to characterize the respective source rocks. Coals and sediments are bearing humic type organic matter, which have hydrogen indices (HI) of up to 300 mgHC/gTOC, indicating a certain content of liptinitic material. The stable carbon isotope ratios (δ¹³C) of the kerogen vary from −23.1 to −27.7‰. Air-free calculated gases contain hydrocarbons up to C₅, carbon dioxide (<1%) and a considerable amount of nitrogen (up to 38%). The gaseous hydrocarbons are dominated by methane (>98%). The stable carbon isotope ratios of methane, ethane and propane are defined as δ¹³C₁: −51.1 to −48.3‰, δ¹³C₂: −37.9 to −25.3‰, δ¹³C₃: −26.0 to −19.2 ‰, respectively. The δD₁ values of methane range from −190 to −178‰. According to its isotopic composition, methane is a mixture, partly generated bacterially, partly thermogenic. Molecular and isotopic composition of the gases and organic geochemical properties of possible source rocks indicate that the thermogenic gas generation took place in coals and organic rich shales of the Westphalian-A Kozlu formation. The bacterial input can be related to a primary bacterial methane generation during Carboniferous and/or to a recent secondary bacterial methane generation. However, some peculiarities of respective isotope values of headspace gases can also be related to the desorption process, which took place by sampling.     

辽东湾地区辽中凹陷东营组烃源岩评价

依据烃源岩地球化学实验手段和油气地化理论,对辽东湾地区辽中凹陷东营组东二下段(Ed^2-1)和东三段(Ed³)地层进行了有机地化分析。在实验获取总有机碳(TOC)、生烃潜量(S₁+S₂)、氢指数(I_H)、氢碳比(H/C)、氧碳比(O/C)、最大热解峰温(T_max)、镜质体反射率(Ro)等有机地化参数的基础上,对有机质丰度、类型、成熟度等进行了系统分析,同时对东营组烃源岩进行了综合评价。研究表明,东二下段S₁+S₂集中在0~3 mg/g,TOC集中在0%~1.5%;东三段S₁+S₂集中分布在4~9 mg/g之间,TOC集中分布在1%~1.25%。东二下段有机质类型主要是III型,东三段有机质类型为II₁、II₂型。东二下段Ro < 0.5,东三段Ro > 0.5,并且随着深度的增加东三段烃源岩Ro相应的增加。T_max随着深度的增加呈现出先增加后减少的异常现象,该种异常现象出现的原因与烃源岩有机质类型和有机质丰度之间存在很大关联。     

海相成熟干酪根生气潜力评价方法研究

高成熟阶段干酪根热解氢指数（HI）非常低,在热成熟度指标镜质组反射率Ro为2.0%以上的Ⅰ或Ⅱ型有机质,一般都在20 mg/gTOC以下,甚至接近0 mg/gTOC,因此,一般认为这种干酪根生烃能力极低。本文通过对不同成熟阶段的干酪根采用元素分析和热解模拟实验相结合的方法,发现HI指数很低的高过成熟阶段干酪根仍然具有一定的生气能力,生气潜力是HI指数的数倍,如HI指数为12 mg/gTOC的样品,H/C原子比为046,生气能力仍然为65 mg/gTOC,占总生烃能力的15%左右,说明成熟—过成熟有机质HI指数不适合衡量生气潜力。同时发现,干酪根生气能力与H/C原子比具有极好相关性,相关系数达到096,通过回归公式所获得有效生气干酪根H/C原子比下限为026。     

Lithostratigraphic setting and P-T metamorphic evolution for the Dora Maira Massif along the Piedmont Zone boundary (middle Susa Valley,NW Alps)

A new structural and petrological study, associated with a detailed geological mapping, allowed to better understand the tectonic relationships between the Dora Maira Massif and the Piedmont Zone in the middle Susa Valley. In the study area, a thick sequence of calcschists, previously attributed to the stratigraphic cover of the Dora Maira, is interpreted as belonging to the Piedmont Zone. Four deformation phases were identified: D₁ represents the eclogite facies stage, D₂ developed under greenschist facies conditions, transposed the early foliation and was responsible for the development of the regional schistosity S₂. D₃ is characterized by close to open folds with N dipping axial surfaces and finally, D₄ developed macro-scale folds with E-dipping axial planes. Structural analyses allow to infer a relative timing for the tectonic contact between the two nappes which were coupled after the eclogite facies metamorphism but before the development of the S₂ foliation under greenschist facies conditions. Petrographic investigation into metapelite samples permitted to identify two main metamorphic assemblages within the Dora Maira polymetamorphic basement: M₁ (Phe + Pg + Cld + Grt + ChlI + Qtz + Rt) assemblage defines the S₁ relict foliation, while M₂ (Ms + Pg + Ab + ChlII + Qtz + Ilm ± Bt) assemblage is related to the regional foliation S₂. PERPLE_X pseudosection modelling allowed to reconstruct a P-T path for a garnet–chloritoid-bearing micaschist from the northern part of the Dora Maira Massif, which reached eclogite facies conditions at 18–20 kbar and 515–525°C (M₁/S₁ event) and then was exhumed during increasing T (10–11 kbar and 555–565°C). The M₂ assemblage defining the S₂ regional foliation developed at P < 7 kbar and T < 575°C. According to the structural evolution, the tectonic coupling between Dora Maira and Piedmont Zone took place during exhumation along the subduction channel.     

Petrology of a non-classical Barrovian inverted metamorphic sequence from the western Arunachal Himalaya, India

In this study, we reconstruct the inverted metamorphic sequence in the western Arunachal Himalaya using combined structural and metamorphic analyses of rocks of the Lesser and Greater Himalayan Sequences. Four thrust-bounded stratigraphic units, which from the lower to higher structural heights are (a) the Gondwana rocks and relatively weakly deformed metasediments of the Bomdila Group, (b) the tectonically interleaved sequence of Bomdila gneiss and Bomdila Group, (c) the Dirang Formation and (d) the Se La Group are exposed along the transect, Jira–Rupa–Bomdila–Dirang–Se La Pass. The Main Central thrust, which coincides with intense strain localization and the first appearance of kyanite-grade partial melt is placed at the base of the Se La Group.Five metamorphic zones from garnet through kyanite, kyanite migmatite, kyanite-sillimanite migmatite to K-feldspar-kyanite-sillimanite migmatites are sequentially developed in the metamorphosed low-alumina pelites of Dirang and Se La Group, with increasing structural heights. Three phases of deformation, D₁–D₂–D₃ and two groups of planar structures, S₁ and S₂ are recognized, and S₂ is the most pervasive one. Mineral growths in all these zones are dominantly late-to post-D₂, excepting in some garnet-zone rocks, where syn-D₁ garnet growths are documented. Metamorphic isograds, which are aligned parallel to S₂ were subsequently folded during D₃. The deformation produced plane-non-cylindrical fold along NW–SE axis.In the garnet-zone, peak metamorphism is marked by garnet growth through the reaction biotite + plagioclase → garnet + muscovite. An even earlier phase of syn-D₁ garnet growth occurred in the chlorite stability field with or without epidote. In the kyanite-zone metapelites, kyanite appeared via the pressure-sensitive reaction, garnet + muscovite → kyanite + biotite + quartz. Staurolite was produced in the same rock by retrograde replacement of kyanite following the reaction, garnet + kyanite + H₂O → staurolite + quartz. These reactions depart from the classical kyanite- and staurolite-isograd reactions in low-alumina pelites, encountered in other segments of eastern Himalaya. In the metapelites, just above the kyanite-zone, melting begins in the kyanite field, through water-saturated and water-undersaturated melting of paragonite component in white mica. Leucosomes formed through these reactions are characteristically free of K-feldspar, with sodic plagioclase and quartz as the dominant constituents. With increasing structural height, the melting shifts to water-undersaturated melting of muscovite component of white mica, producing an early K-feldspar + kyanite and later K-feldspar + sillimanite assemblages and granitic leucosomes.Applications of conventional geothermobarometry and average P–T method reveal near isobaric (at P  8 kbar) increase in peak metamorphic temperatures from 550 °C in the garnet-zone to >700 °C for K-feldspar-kyanite-sillimanite-zone rocks. The findings of near isobaric metamorphic field gradient and by the reconstruction of the reaction history, reveal that the described inverted metamorphic sequence in the western Arunachal Himalaya, deviates from the classical Barrovian-type metamorphism. The tectonic implication of such a metamorphic evolution is discussed.     

Interrelationship of TOC,As, Fe,Mn, Al and Si in shallow alluvial aquifers in Chapai-Nawabganj,Northwestern Bangladesh: implication for potential source of organic carbon

Two boreholes and ten piezometers in the Ganges flood plain were drilled and installed for collecting As-rich sediments and groundwater. Groundwater samples from the Ganges flood plain were collected for the analysis of cations (Ca²⁺, Mg²⁺, K⁺, Na⁺), anions (Cl⁻, NO₃ ⁻, SO₄ ²⁻), total organic carbon (TOC), and trace elements (As, Mn, Fe, Sr, Se, Ni, Co, Cu, Mo, Sb, Pb). X-ray powder diffraction was performed to characterize the major mineral contents of aquifer sediments and X-ray fluorescence (XRF) to analyze the major chemical composition of alluvial sediments. Results of XRF analysis clearly show that fine-grained sediments contain higher amounts of trace element because of their high surface area for adsorption. Relative fluorescence index (15–38 QSU) of humic substance in groundwater was measured using spectrofluorometer, the results revealed that groundwater in the Ganges flood plain contains less organic matter (OM). Arsenic concentration in water ranges from 2.8 to 170 μg/L (mean 50 μg/L) in the Ganges flood plain. Arsenic content in sediments ranges from 2.1 to 14 mg/kg (mean 4.58 mg/kg) in the flood plains. TOC ranges from 0.49 to 3.53 g/kg (mean 1.64 g/kg) in the Ganges flood plain. Arsenic is positively correlated with TOC (R ² = 0.55) in sediments of this plain. Humic substances were extracted from the sediments from the Ganges flood plain. Fourier transform infrared analysis of the sediments revealed that the plain contains less humic substances. The source of organic carbon was assigned from δ¹³C values obtained using elemental analysis-isotope ratio mass spectrometry (EA-IRMS); the values (−10 to −29.44‰) strongly support the hypothesis that the OM of the Ganges flood plain is of terrestrial origin.     

Solution mechanisms of silicate in aqueous fluid and H2O in coexisting silicate melts determined in-situ at high pressure and high temperature

The structure of H₂O-saturated silicate melts, coexisting silicate-saturated aqueous solutions, and supercritical silicate liquids in the system Na₂O·4SiO₂–H₂O has been characterized with the sample at high temperature and pressure in a hydrothermal diamond anvil cell (HDAC). Structural information was obtained with confocal microRaman and with FTIR microscopy. Fluids and melts were examined along pressure-temperature trajectories defined by the isochores of H₂O at nominal densities, ρ_fluid, (from EOS of pure H₂O) of 0.90 and 0.78 g/cm³. With ρ_fluid = 0.78 g/cm³, water-saturated melt and silicate-saturated aqueous fluid coexist to the highest temperature (800 °C) and pressure (677 MPa), whereas with ρ_fluid = 0.90 g/cm³, a homogeneous single-phase liquid phase exists through the temperature and pressure range (25–800 °C, 0.1–1033 MPa). Less than 5 vol% quartz precipitates near 650 °C in both experimental series, thus driving Na/Si-ratios of melt + fluid phase assemblages to higher values than that of the Na₂O·4SiO₂ starting material.Molecular H₂O (H₂O°) and structurally bonded OH groups were observed in coexisting melts and fluids as well as in supercritical liquids. Their OH/(H₂O)-ratio is positively correlated with temperature. The OH/(H₂O)° in melts is greater than in coexisting fluids. Structural units of Q³, Q², Q¹, and Q⁰ type are observed in all phases under all conditions. An expression of the form, 12Q³ + 13H₂O2Q² + 6Q¹ + 4Q⁰, describes the equilibrium among those structural units. This equilibrium shifts to the right with increasing pressure and temperature with a ΔH of the reaction near 425 kJ/mol.     

The effect of organic matter type and organic carbon content on Rock-Eval hydrogen index in oil shales and source rocks

The amount of “gas-prone” kerogen (woody, fungal and “inert”) and the organic carbon content (TOC) are the two predominant factors affecting the hydrogen index (HI) in the 226 samples of lacustrine and marine oil shales and source rocks studied. HI decreases as a function of the amount of “gas-prone” kerogen and increases as a function of TOC. In addition, the type of amorphous kerogen influences the hydrogen index, and this can be roughly estimated from the fluorescence intensity of the amorphous kerogen. Nearly eighty percent of the variation in HI in these samples can be accounted for by the percentage of “gas-prone” kerogen, the TOC content, and the fluorescence of the amorphous kerogen in a multiple regression analysis.Hydrogen index increases as a function of TOC up to about 10% TOC (the relationship can be approximated by a quadratic equation) and then levels off. A possible explanation for this is that the capability of a rock to generate and expel hydrocarbons during pyrolysis increases with TOC. When the retention capacity of the rock matrix is saturated (at about 10% TOC) further increases in TOC have no effect on HI. It is also possible that the quality (i.e. oil-proneness) of the amorphous kerogen is poorer in low TOC samples than in high TOC samples.The samples came from the following oil shales and source rocks: Rundle (Queensland Eocene-Miocene), Mae Sot (northwestern Thailand, Eocene-Pliocene), River River (northwestern Colorado, Eocene), Toolebuc (western Queensland, Late Albian), the “Posidonienschiefer” (southwestern Germany, Toarcian), an Argentinian lacustrine deposit (Eocene-Miocene), the Kimmeridgian sections from four North Sea wells (blocks 21, 30, and 210), Monterey Shale (California, Miocene), and sections from six wells from the Alaskan Tertiary (North Slope, North Aleutian Shelf, Navarin Basin, Norton Sound). Most samples appear to be thermally immature (T.A.I. less than 1.8; R_o less than 0.6%) so they should be considered only potential source rocks.The lacustrine oil shales have a higher conversion ratio (yeild/TOC or S₁ + S₂/TOC) than do the marine oil shales in samples with only amorphous and algal kerogen. These, in turn, have a higher conversion ratio than the marine source rocks. These differences are roughly reflected in the fluorescence intensity of the amorphous kerogen. Free hydrocarbons are higher in the marine source rocks than in the marine oil shales, and are lowest in the lacustrine oil shales.     

Organic geochemical evidence for a regional stratigraphic thermal event in East China

A systematic investigation of the petroleum exploratory well N-13 within the Huangqiao region, Lower Yangtze Basin, East China, has been carried out using multiple analytical techniques of organic geochemistry. The past occurrence of a thermal event has been recognized based on changes in optical vitrinite reflectance (R_o), pyrolysis peak temperature (T_max) and chemical hydrogen index (HI), potential degradation rate (D), the atomic H/C ratio and dimethylphenanthrene ratios (DPR, DPR₁ and DPR₂) in the sedimentary rocks. The geological significance of this thermal event is discussed in this paper.     

Calcareous nannoplankton, planktonic foraminiferal, and carbonate carbon isotope stratigraphy of the Cenomanian–Turonian boundary section in the Ultrahelvetic Zone (Eastern Alps, Upper Austria)

Ultrahelvetic units of the Eastern Alps were deposited on the distal European continental margin of the (Alpine) Tethys. The Rehkogelgraben section (“Buntmergelserie”, Ultrahelvetic unit, Upper Austria) comprises a 5 m thick succession of upper Cenomanian marl-limestone cycles overlain by a black shale interval composed of three black shale layers and carbonate-free claystones, followed by lower Turonian white to light grey marly limestones with thin marl layers. The main biostratigraphic events in the section are the last occurrence of Rotalipora and the first occurrences of Helvetoglobotruncana helvetica and Quadrum gartneri. The thickest black shale horizon has a TOC content of about 5%, with predominantly marine organic matter of kerogen type II. Vitrinite reflectance and Rock-Eval parameter T_max (<424 °C) indicate low maturity. HI values range from 261 to 362 mg HC/g TOC. δ¹³C values of bulk rock carbonates display the well documented positive shift around the black shale interval, allowing correlation of the Rehkogelgraben section with other sections such as the Global Boundary Stratotype Section and Point (GSSP) succession at Pueblo, USA, and reference sections at Eastbourne, UK, and Gubbio, Italy. Sediment accumulation rates at Rehkogelgraben (average 2.5 mm/ka) are significantly lower than those at Pueblo and Eastbourne.     

Characteristics and Evaluation of the High-Quality Source Rocks of Cretaceous Continental Shale Oil in Tonghua Basin,China

The presence of shale oil in the Cretaceous Hengtongshan Formation in the Tonghua Basin, drilled by the well TD-01, has been discussed in this geological investigation for the first time. To evaluate the high-quality source rocks of Cretaceous continental shale oil, the distribution characteristics and the evolution of the ancient environment, samples of shale were systematically analyzed in terms of sedimentary facies, organic geochemistry, and organic carbon isotopic composition. The results demonstrate that a TOC value of 1.5% represents the lower-limit TOC value of the high-quality source rocks. Source rocks have an aggregate thickness of 211 m and contain abundant organic matter, with TOC values of 2.69% on average and a maximum value over 5.44%. The original hydrocarbon-generative potential value(S_1+S_2) is between 0.18 mg/g and 6.13 mg/g, and the Ro is between 0.97% and 1.40%. The thermal maturation of the source rocks is relatively mature to highly mature. The δ¹³C value range is between -34.75‰ and -26.53‰. The ratio of saturated hydrocarbons to aromatic hydrocarbons is 1.55 to 5.24, with an average of 2.85, which is greater than 1.6. The organic types are mainly type Ⅱ_1, followed by type Ⅰ. The organic carbon source was C_3 plants and hydrophytes. The paleoclimate of the Hengtongshan Formation can be characterized as hot and dry to humid, and these conditions were conducive to the development of high-quality source rocks. A favorable paleoenvironment and abundant organic carbon sources provide a solid hydrocarbon generation base for the formation and accumulation of oil and gas in the shale of the Tonghua Basin.     

Organic geochemistry and depositional environment of the Aptian bituminous limestone in the Kale Gümüşhane area (NE-Turkey): An example of lacustrine deposits on the platform carbonate sequence

The Jurassic–Lower Cretaceous aged carbonate sequence is widely exposed in the southern zone of Eastern Pontides. Aptian black bituminous limestone is found in the upper part of this sequence in the Kale area (Gümüşhane). This limestone contains faunal remains (e.g., gastropod, ostracod, characean stems and miliolid type benthic foraminifera) that indicate a freshwater, lacustrine depositional environment.The total organic carbon (TOC) values of the bituminous limestone samples range from 0.11–1.30% with an average TOC value of 0.54%. The hydrogen index (HI) varies from 119–448 mg HC/g TOC (average HI 298 mg HC/g TOC) indicating that the limestone contains gas prone as well as oil prone organic matter. Pyrolysis data prove that the organic matter content in the bituminous limestone consists of Type II kerogen. The average T_max value for bituminous limestone samples is 438 °C (434–448 °C). Bitumen/TOC ratios for bituminous limestone are 0.05 and 0.04. The T_max values and the ratios indicate that the bituminous limestone samples contain early mature to mature organic matter.Analysis of solvent extracts from the two richest bituminous limestones show a predominance of high carbon number (C₂₆–C₃₀) n-alkanes. The Pr/Ph ratio and CPI value are 1.34 and 0.96, respectively. C₂₉ is the dominant sterane, with C₂₉ > C₂₇ > C₂₈. The bituminous limestone samples have low C₂₂/C₂₁ ratios, high C₂₄/C₂₃ tricyclic terpane ratios and very low C₃₁R/C₃₀ hopane ratios (<0.25). These data are consistent with the bituminous limestones being deposited in a lacustrine environment.     

Analysis of relationships between geochemical parameters of petroleum potential in related source and carbonaceous materials

A worldwide data set of 1,085 samples containing organic matter of the type II/III kerogen from Carboniferous to Cenozoic was used to analyse the evolution of the hydrogen index (HI), quality index (QI), and bitumen index (BI) with increasing thermal maturity. The HI_max, QI_max and BI_max lines were defined, based on statistical analysis and cross-plots of HI, QI and BI versus the vitrinite reflectance (%Ro) and T _max (°C). The constructed HI, QI and BI bands were broad at low maturities and gradually narrowed with increasing thermal maturity. The petroleum generation potential is completely exhausted at a vitrinite reflectance of 2.0–2.2 % and T _max of 510–520 °C. An increase in HI and QI suggests extra petroleum potential related to changes in the structure of the organic material. A decline in BI signifies the start of the oil window and occurs within the vitrinite reflectance range 0.75–1.05 % and T _max of 440–455 °C. Furthermore, petroleum potential can be divided into four different parts based on the cross-plot of HI versus %Ro. The area with the highest petroleum potential is located in “Samples and methods” with %Ro = 0.6–1.0 %, and HI > 100. Oil generation potential is rapidly exhausted at “Results and discussion” with %Ro > 1.0 %. This result is in accordance with the regression curve of HI and QI with %Ro based on 80 samples with %Ro = 1.02–3.43 %. The exponential equation of regression can thus be achieved: HI = 994.81e^?1.69Ro and QI = 1,646.2e^?2.003Ro (R ² = 0.72). The worldwide organic material data set defines two range of oil window represented by the upper and lower limits of the BI band: %Ro 0.75–1.95 %, T _max 440–525 °C, and %Ro 1.05–1.25 %, T _max 455–465 °C, respectively.