Comparison of oil shales and kerogen concentrates by 13C nuclear magnetic resonance

Six oil shales and their kerogen concentrates have been studied using ¹³C CP/MAS NMR techniques to study the distribution of organic carbon species. It is found that if the aromatic and aliphatic regions are divided at about 80 or 100 ppm, the apparent aromaticities of a raw shale and its kerogen concentrate are in good agreement. The presence of oxygen-substituted carbons in the raw shales and their depletion in the kerogen concentrates are observed and discussed.     

Solid state C NMR studies of selected oil shales from Queensland, Australia

Solid state ¹³C NMR techniques of cross polarization with magic-angle spinning, and interrupted decoupling have been employed to examine the nature of the organic matter in eight kerogen concentrates representing five Tertiary deposits in Queensland, Australia. The NMR results show that five of the kerogens have high proportions of aliphatic carbon in their organic matter and correspond to Type I–II algal kerogens. Three of the kerogens, derived from carbonaceous shales, have a high proportion of aromatic carbon in their organic matter and correspond to Type III kerogens. The fractions of aliphatic carbon in all the kerogens, regardless of type, are shown to correlate with the conversion characteristics of the corresponding raw shales during Fischer assay. Interrupted decoupling NMR results show the presence of more oxygen-substituted carbon in the carbonaceous shales, which may account for the greater CO₂ evolution and phenolic materials found in the pyrolysis products of the carbonaceous shales.     

13C NMR measurements of the genetic potentials of oil shales

Cross polarization, magic-angle spinning ¹³C NMR measurements have been made on raw oil shales that represent a variety of geologic ages, origins, depositional environments and source locations. A high degree of correlation was established between the fraction of aliphatic carbon measured by ¹³C NMR, and the genetic potential, calculated from Fischer assay data. The correlation is independent of the type of kerogen in the raw shale, and its degree of evolution. A short discussion on the validity of various correlations between physical/chemical properties of oil shales and Fischer assay oil yields is given.     

Investigation of the pyrolytic liberation of molecular nitrogen from Palaeozoic sedimentary rocks

Open-system non-isothermal pyrolysis up to 1,200°C in combination with elemental analysis was used to study the thermal liberation of molecular nitrogen (N₂) from sedimentary rocks and kerogen concentrates of Palaeozoic age from the Central European Basin system and an Eocene shale (Liaohe Basin, China) with a high content (36%) of ammonium feldspar (buddingtonite). The N/C_org (atomic) ratios of the kerogen concentrates ranged from 0.005 to 0.014, which represents the range commonly observed for coals. Bulk N/C_org ratios of the Palaeozoic shales extended from 0.035 to 0.108, indicating the presence of significant amounts of inorganic nitrogen. Namurian A and A-B (CnA; CnA-B) samples typically exhibited the earliest onset of N₂ generation with intense, characteristic peaks around 600°C. N₂ liberation from the buddingtonite-rich sample occurred at higher temperatures, with a broad peak around 700°C. Pyrograms of the kerogen concentrates showed no or strongly reduced N₂ generation in the 500–700°C range. On-line isotope-specific analysis of the pyrolytically liberated N₂ on one sample revealed a variability of ∼10‰ in the δ¹⁵N values and a steady increase in δ¹⁵N with temperature during the main phase of N₂ generation.     

13C Nuclear magnetic resonance studies of kerogen from Cretaceous black shales thermally altered by basaltic intrusions and laboratory simulations

Cretaceous black shales from DSDP Leg 41, Site 368 in the Eastern Atlantic Ocean were thermally altered during the Miocene by an intrusive basalt. The sediments overlying and underlying the intrusive body were subjected to high temperatures (up to ~ 500°C) and, as a result, their kerogen was significantly altered. The extent of this alteration has been determined by examination by means of ¹³C nuclear magnetic resonance, using cross polarization/magic-angle spinning (CP/MAS). Results indicate that the kerogen becomes progressively more aromatic in the vicinity of the intrusive body. Laboratory heating experiments, simulating the thermal effects of the basaltic intrusion, produced similar results on unaltered shale from the drill core. The ¹³C CP/MAS results appear to provide a good measure of thermal alteration.     

Organic Material and Trace Elements of Bituminous Rocks in the Ozankiiy Field, Ankara, Turkey

Bituminous rocks in the Ozankoey （Ankara） field are different from those of the Paleocene- Eocene Mengen and Giineytepe （Bolu） regions in metal enrichment levels. Organic carbon （Corg） content of organic material-rich rocks in the Ozankoey （Ankara） field is 3.66-40.72% wt averaging 14.34%. The dominant organic materials are algae/amorphous accompanied by minor amount of herbaceous material （The dominant kerogen type is Type-I with a limited amount of Type-Ⅱ kerogen.）. The bituminous rocks in the Ozankoey field are enriched in heavy metals such as Ni, Mn, As and Cr. In comparison with the average enrichment values of dements, Ni, Mn, As and Cr in bituminous shales of the Ozankoey field are as about 4.38, 14.93, 10.90 and 5.58 times as average values. The average concentrations of these heavy metals are also as high as 215× 10^-6, 828 × 10^-6, 58.54 × 10^-6, and 148 × 10^-6 respectively. In addition, sorption properties of day and organic materials are also important for metal enrichments in the bituminous shales.     

Distribution and geochemical significance of trace elements in shale rocks and their residual kerogens

There is a dearth of information about the distribution of trace elements in kerogen from shale rocks despite several reports on trace element composition in many shale samples. In this study, trace elements in shale rocks and their residual kerogens were determined by inductively coupled plasma–mass spectrometry. The results from this study show redox-sensitive elements relatively concentrated in the kerogens as compared to the shales. This may be primarily due to the adsorption and complexation ability of kerogen, which enables enrichment in Ni, Co, Cu, and Zn. For the rare earth elements (REEs), distinct distribution characteristics were observed for shales dominated by terrigenous minerals and their kerogen counterparts. However, shales with less input of terrigenous minerals showed similar REE distribution patterns to their residual kerogen. It is speculated that the distribution patterns of the REEs in shales and kerogens may be source-related.     

Gas-generation potential of shales in small and medium-sized basins: a case study from the Xuanhua Basin,north China

Abstract

Small- and medium-sized basins are widely distributed, and some contain commercial gas reservoirs demonstrating their gas-generation potential. The Xuanhua Basin, which is a small-sized coal-bearing basin in north China, includes a promising target for shale-gas exploration in the Xiahuayuan Formation. In this study, we used this basin as a case study to assess the critical geochemical features for small or medium-sized basins to form commercial gas reservoirs. Total organic carbon (TOC) analysis, Rock-Eval pyrolysis, microscopic observation of macerals, vitrinite reflectance measurement and kerogen stable carbon isotope analysis were performed to characterise the organic geochemistry of the Xiahuayuan shales. The original total organic carbon (TOC_o) content and hydrocarbon-generative potential (S_2o) were reconstructed to further evaluate the gas-generation potential of these shales. In addition, geochemical data of shales from other similar-sized basins with gas discoveries were compared. The results showed that the kerogen from the Xiahuayuan Formation is Type III (gas-prone), and macerals are dominated by vitrinite. TOC values showed a strong heterogeneity in the vertical profiles, with most higher than 1.5?wt%. The measured R_o values ranged from 1.4 to 2.0%. However, thermal maturity was not correlated with the present-day burial depth with higher maturity in the wells closest to the diabase intrusion centre. The remaining generation potential (S₂) averaged 0.91?mg HC/g rock, equal to 1.4?cm³ CH₄/g rock, and the average amount of hydrocarbon generated was 4.33?cm³ CH₄/g rock. In small and medium-sized basins, the TOC content of commercially developed gas shales ranged from 0.5 to 2.5?wt%, organic matter was mainly humic (gas-prone), and the burial depth was generally shallow. Biogenic gas reservoirs for commercial exploitation tend to have larger shale thicknesses (120–800?m) than thermogenic gas reservoirs (60–90?m).

1. The Xiahuayuan Formation is a good gas-source rock with gas-prone kerogen type, relatively high TOC values and moderate thermal maturity.

2. The average amount of hydrocarbon generated from the Xiahuayuan shales is about 4.33?cm³ CH₄/g rock, indicating a potential to form a shale gas reservoir.

3. Owing to the influence of diabase intrusions, the Xiahuayuan shales have entered the dry gas window at relatively shallow-buried depths.

4. Small- and medium-sized basins have the potential to generate commercial gas reservoirs with the generated volume mainly a product of the thickness and maturity of black shales.

     

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 matter in Silurian rocks from the Chernov uplift

This study presents data on the composition of organic matter from the Late Silurian sediments of the Chernov uplift. These sediments are characterized by low C_org contents, which may reach 1–3% in individual layers. A relatively high thermal maturity of organic matter is confirmed by polycyclic biomarker distributions and Rock-Eval pyrolyisis data. Despite its higher thermal maturity level (T _max = 456°C), kerogen in carbonaceous shales from the Padymeityvis River exhibits good preservation of long-chain n-alkyl structures, which are readily identified in the ¹³C NMR spectra and by the molecular analysis of the kerogen pyrolysis products.     

Changes in the composition of bitumen extracts and chemical structure of kerogen during hydrous pyrolysis

The paper presents data on the composition of biomarkers from bitumen extracts and the chemical structure of kerogen from C_org-rich sedimentary rocks before and after hydrothermal treatment in an autoclave at 300°C. Samples selected for this study are kukersite and Ordovician Dictyonema shale from the Baltics, Domanik oil shale from the Ukhta region, Upper Permian brown coal from the Pre-Ural foredeep, carbonaceous shale from the Oxfordian horizon of the Russian plate, and Upper Jurassic oil shales from the Sysola oil shale bearing region. The rocks contain type I, II, III, and II-S kerogens. The highest yield of extractable bitumen is achieved for Type II-S kerogen, whereas Type III kerogen produces the lowest amount of bitumen. The stages of organic matter thermal maturation achieved during the experiments correspond to a transition from PC_2–3 to MC_1–2. The ¹³C NMR data on kerogen indicate that the aromatic structures of geopolymers underwent significant changes.     

Environmental control of carbon isotope variations in Pennsylvania black-shale sequences, Midcontinent, U.S.A.

A reversal of the conventional carbon isotope relationship, “terrestrial-lighter-than-marine” organic matter, has been documented for two Pennsylvanian (Desmoinesian) cyclothemic sequence cores from the Midcontinent craton of the central United States. “Deep” water organic-rich phosphatic black shales contain a significant proportion of algal-derived marine organic matter (as indicated by organic petrography, Rock-Eval hydrogen index and ratios) and display the lightest δ¹³C-values (max −27.80‰ for kerogen) while shallower water, more oxic facies (e.g. fossiliferous shales and limestones) contain dominantly terrestrial organic matter and have heavier δ¹³C_kerogen-values (to −22.87‰ for a stratigraphically adjacent coal). δ¹³C-values for extract fractions were relatively homogeneous for the organic-rich black shales with the lightest fraction (often the aromatics) being only 1‰, or less, more negative than the kerogen. Differences between extract fractions and kerogens were much greater for oxic facies and coals (e.g. saturates nearly 5‰ lighter than the kerogen).A proposed depositional model for the black shales calls upon a large influx of nutrients and humic detritus to the marine environment from the laterally adjacent, extremely widespread Pennsylvanian (peat) swamps which were rapidly submerged by transgression of the epicontinental seas. In this setting marine organisms drew upon a CO₂-reservoir which was in a state of disequilibrium with the atmosphere, being affected by isotopically light “recycled-CO₂” derived from the decomposition of peaty material in the water column and possibly from the anoxic diagenesis of organic matter in the sediments.     

Geological and geochemical characteristics of the Middle–Lower Jurassic shales in the Kuqa Depression,Tarim Basin: an evaluation of shale gas resources

Middle–Lower Jurassic terrigenous shales constitute a set of significant hydrocarbon source rocks in the Kuqa Depression of the Tarim Basin. Until recently, however, most investigations regarding this set of hydrocarbon source rocks have mainly focused on conventional oil and gas reservoirs, and little research has been conducted on the formation conditions of shale gases. This research, which is based on core samples from nine wells in the Kuqa Depression, investigated the geological, geochemical, mineralogical and porosity characteristics of the shales, analysed the geological and geochemical conditions for the formation of shale gases, and evaluated the shale gas resource potential. The results show that the distribution of the Middle–Lower Jurassic shales is broad, with thicknesses reaching up to 300–500 km. The total organic carbon (TOC) content is relatively high, ranging from 0.2 to 13.5 wt% with a mean of 2.7 wt%. The remaining hydrocarbon generative potential is between 0.1 and 22.34 mg/g, with a large range of variation and a mean value of 3.98 mg/g. It is dominated by type III kerogen with the presence of minor type II₁ kerogen. The vitrinite reflectance values range from 0.517 to 1.572%, indicating the shales are in a mature or highly mature stage. The shales are mainly composed of quartz (19–76%), clay (18–68%) and plagioclase (1–10%) with mean contents of 50.36 wt%, 41.42 wt%, and 3.37 wt%, respectively. The pore spaces are completely dominated by primary porosity, secondary porosity and microfractures. The porosity is less than 10% and is mainly between 0.5 and 4%, and the permeability is generally less than 0.1 mD. These results classify the shale as a low-porosity and ultra-low-permeability reservoir. The porosity has no obvious correlation with the brittle or clay mineral contents, but it is significantly positively correlated with the TOC content. The maximum adsorbed gas content is between 0.82 and 8.52 m³/t with a mean of 3.37 m³/t. In general, the shale gas adsorption content increases with increasing the TOC content, especially when the TOC content is greater than 1.0%. The volumetric method, used to calculate the geological resources of the Middle–Lower Jurassic shales in the Kuqa Depression, shows that the geological resources of the Middle and Lower Jurassic shales reach 667.681 and 988.115 × 10⁹ m³, respectively with good conditions for the formation of shale gas and good prospects for shale gas exploration.     

Kerogen based characterization of major gas shales: Effects of kerogen fractionation

Research into the origin and the mode of entrapment and expulsion of natural gas from unconventional plays requires the isolation and separation of kerogen in its purest and most intact form from the rock matrix. This study expands on the comparative analysis of the effects that isolation methods, conservative closed system versus conventional open system, have on kerogen’s elemental, isotopic and physical properties. Four major gas shales, including the Barnett, the Marcellus, the Haynesville and a Polish gas shale, were chosen. In addition, the Monterey shale, though not strictly a gas shale, was included to address the effects on sulfur rich, Type II-S kerogen.Results indicate that the kerogen residues from the conventional open system method showed lower recovery and higher mineral content than those from the conservative closed system method. Differences were manifested in the elemental analysis data, where kerogens isolated using the open system method showed a significant deficit in the organic C, H, O, S and N material balance. Furthermore, the recovered residues show different sulfur content and δ³⁴S composition, most likely attributable to differences in pyrite content. Nevertheless, the relative abundances of the various macerals in the kerogen residues from the same parent shale are not very different; neither was the bulk δ¹³C composition of the recovered residues. This is not particularly surprising, considering that in all the five cases examined in this study, the organic matter was fairly homogeneous.     

Oil-source correlations of the lower tertiary in the Dongtai sag of the Subei Basin

A series of biomarkers is used to explore the bio-inputs of source rocks and oils. Oils from the Dongtai sag of the Subei Basirr are characterized by abundant gammacerane and 4-methyl steranes. Both Ef⁴ and Ef² source shales contain type-II₁ kerogen. Ef⁴ is different from Ef² in biomarker distribution and generated oil. The former has higher Pr/Ph and 4-methyl sterane/sterane ratios, but the latter has more abundant β-carotane. The presence of immature oils and source rocks in the Hai’an depression indicates that the immature oils are of commercial value.     

Fragment of the chemical structure of type II and II-S kerogen in the Upper Jurassic and Upper Devonian formations of the East European Platform

A model is proposed for a fragment of the chemical structures of the geopolymers based on elemental analysis and the study of the composition of the pyrolysis products of kerogen from the Upper Jurassic and Devonian formations in the East European Platform. The S_org/C ratio in kerogen from oil shales from J₃v₂ is 0.4 or higher, and this kerogen belongs to type II-S, while kerogen from the Domanik rocks does not contain S and belongs to type II. The composition of the pyrolysis products of the Upper Jurassic kerogen testifies to the presence of polysulfur-bound structures in this geopolymer, whose thermolysis results in disulfuric cyclic compounds. No structures of this type are contained in Domanik kerogen. Oxygen-bearing groups in J₃v₂ kerogen are thought to be partly concentrated on simple-ether bonds, whereas D₃dm kerogen is likely dominated by compound-ether and carboxyl structures. Nitrogen-bearing structures in kerogen from Upper Jurassic and Domanik formations are of different genesis: while nitrogen-bearing structures in Jurassic kerogen are mostly aminoacids, Domanik kerogen contains chitin derivatives.     

Lasers in organic petrology and organic geochemistry, II. In-situ laser micropyrolysis-GCMS of coal macerals

The development and preliminary results of a novel laser micropyrolysis-gas chromatography, mass spectrometry (LMPy-GCMS) system are described. Short exposures of near-infra red (IR) laser radiation focused through a microscope's optics onto a specific, targeted maceral within a polymaceralic organic-rich shale or coal are used to release the thermal evaporation and pyrolysis products from the maceral. The products from multiple exposures on a single maceral type are collectively analyzed online using GCMS. This technique is intended to provide a means of chemically characterizing individual, microscopic organic entities (> 25 μm) in coals and shales without the need to physically separate them from each other (e.g. density gradient centrifugation) or from their mineral matrix (e.g. bulk analysis of kerogen concentrates). Molecular characterization of individual macerals is important in predicting the technological properties of coal and the petroleum generation potential of petroleum source rocks.Different macerals respond differently when exposed to focused near-IR laser radiation due to differences in their heat capacity and heat conduction. The thermal products released during irradiation of macerals (ulminite, alginite, sporinite and fusinite) representing the huminite, liptinite and inertinite maceral groups are presented. Under the appropriate heating, collecting, and trapping conditions, the thermal products liberated are considered representative of the macromolecular structure of the macerals. Structural elucidation of macerals in coals and shales could significantly benefit from concerted efforts of this and other in-situ micro-analytical techniques.     

Carbon isotopes of organic matter from the upper Jurassic oil shales from the Volgian-Pechora shale province and its accumulation mechanisms

The isotopic composition of carbon from the organic matter of late Jurassic oil shales from the Volgian-Pechora shale province is studied. The existence of a dependence between C_org content in the rock and the isotopic composition of kerogen carbon is ascertained. The content of the heavy carbon isotope increases with increasing C_org. This dependence is accounted for by the progressive accumulation of isotopically heavy hydrocarbons of the initial organic matter due to sulfurization. The data on the isotopic composition of individual n-alkanes of bitumen in the rocks and the data on the absence of isotopic fractionation between thermobitumen and the residual kerogen from oil shales from the Volgian-Pechora shale province obtained by treating shale in an autoclave in the presence of water are presented first in this paper.     

湘西北地区寒武系牛蹄塘组页岩气资源前景

湘西北地区牛蹄塘组黑色页岩展布广泛,为寒武纪纽芬兰世—第二世滞留还原条件的沉积产物,适中的埋深和较大的厚度为其提供了良好的气藏条件。对其有机地化参数进行试验分析:TOC值为0.59%～13.05%,均值3.75%,有机质丰富;R_o值为1.87%～4.00%,均值3.05%,成熟度高;干酪根类型以Ⅰ型为主,少量为Ⅱ型,具有良好的生气潜力;矿物组成中脆性矿物含量为33%～87%,平均含量为68%,而黏土总量为13%～43%,平均为26%,脆性矿物/黏土矿物值高,有利于储层改造;页岩孔隙度为0.3%~8.0%,平均为3.3%,渗透率均小于0.04×10^-3μm²,为低孔低渗类型。综合研究表明,牛蹄塘组具有良好的页岩气生储潜力,同时运用条件概率体积法对其资源量进行评估计算,资源量十分可观。在此基础上对湘西北地区牛蹄塘组划分出6个页岩气有利区,为进一步实施页岩气勘查提供依据。     

Geochemical and isotopic approach to maturity/source/mixing estimations for natural gas and associated condensates in the Thrace Basin,NW Turkey

The Tertiary Thrace Basin located in NW Turkey comprises 9 km of clastic-sedimentary column ranging in age from Early Eocene to Recent in age. Fifteen natural gas and 10 associated condensate samples collected from the 11 different gas fields along the NW–SE extending zone of the northern portion of the basin were evaluated on the basis of their chemical and individual C isotopic compositions. For the purpose of the study, the genesis of CH₄, thermogenic C₂₊ gases, and associated condensates were evaluated separately.Methane appears to have 3 origins: Group-1 CH₄ is bacteriogenic (Calculated δ¹³C_C1–C = −61.48‰; Silivri Field) and found in Oligocene reservoirs and mixed with the thermogenic Group-2 CH₄. They probably formed in the Upper Oligocene coal and shales deposited in a marshy-swamp environment of fluvio-deltaic settings. Group-2 (δ¹³C_C1–C = −35.80‰; Hamitabat Field) and Group-3 (δ¹³C_1–C = −49.10‰; Değirmenköy Field) methanes are thermogenic and share the same origin with the Group-2 and Group-3 C₂₊ gases. The Group-2 C₂₊ gases include 63% of the gas fields. They are produced from both Eocene (overwhelmingly) and Oligocene reservoirs. These gases were almost certainly generated from isotopically heavy terrestrial kerogen (δ¹³C = −21‰) present in the Eocene deltaic Hamitabat shales. The Group-3 C₂₊ gases, produced from one field, were generated from isotopically light marine kerogen (δ¹³C = −29‰). Lower Oligoce ne Mezardere shales deposited in pro-deltaic settings are believed to be the source of these gases.The bulk and individual n-alkane isotopic relationships between the rock extracts, gases, condensates and oils from the basin differentiated two Groups of condensates, which can be genetically linked to the Group-2 and -3 thermogenic C₂₊ gases. However, it is crucial to note that condensates do not necessarily correlate to their associated gases.Maturity assessments on the Group-1 and -2 thermogenic gases based on their estimated initial kerogen isotope values (δ¹³C = −21‰; −29‰) and on the biomarkers present in the associated condensates reveal that all the hydrocarbons including gases, condensates and oils are the products of primary cracking at the early mature st age (R_eq = 0.55–0.81%). It is demonstrated that the open-system source conditions required for such an early-mature hydrocarbon expulsion exist and are supported by fault systems of the basin.