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We have recently shown that molecular hydrogen generation from organic matter occurs at high maturity levels (vitrinite reflectance 3–5%) in Lower Cretaceous shales of the Songliao Basin. To evaluate and extend these implications to a wider range of source rock types and organofacies, we report on two Paleozoic maturity suites from Australia, namely the Permian Patchawarra Formation (fluviodeltaic; Type-III; Cooper Basin) and the middle Cambrian Arthur Creek Formation (marine; Type-II; Georgina Basin), and additional mature marine source rocks from Europe and the USA. It can be inferred from high resolution mass spectrometry that rapid growth of aromatic ring systems is the major pathway for the formation of thermogenic molecular hydrogen from all organic matter types. Extensive open system pyrolysis experiments indicate that the main generation pulse occurs in the vitrinite reflectance range 3.5–5.0%. Kinetic parameters were constructed by subtracting the hydrogen associated with hydrocarbon formation from total hydrogen in the open-system experiments via adjustment factors defined by the relative yields of CH4 and H2. A cumulative H2 potential of 20 mg/g TOC is found with maximum rates of generation that are sufficient for feeding the deep biosphere. Back of the envelope calculations indicate ∼3.5E+10 tonnes of in-place accessible H2 globally, which is an order of magnitude lower than in-place shale gas resource estimates. Regionally, inferred here for the Patchawarra Formation in the Nappamerri Trough (Cooper Basin), yields per unit rock volume resemble those of economic shale gas in the Barnett Shale, Fort Worth Basin, USA. Organic particles are, at the SEM-scale (>30 nm), barren of secondary porosity in the case of terrigenous samples at all maturity stages, but show sponge-like porosity in the investigated marine source rocks exhibiting vitrinite reflectance >∼2.0%. Presence of such meso- and macropores is crucial for H2 storage in marine shales, as microporosity (

China has been said to have the largest putative shale gas resources in the world. The highest potential occurs in the Sichuan Basin, with the overmature Qiongzhusi (Cambrian) and Longmaxi (Silurian) Formations as prime exploration targets. Here the likelihood of late gas formation is examined using less mature equivalents from the Georgina Basin (Australia), and the Baltic Basin (Lithuania). We consider the respective roles played by kerogen and polar bitumen in gas generation with reference to the Eagle Ford, Yanchang, Niobrara, and Vaca Muerta Formations. Both of the lower Paleozoic shales are bitumen-poor in a geochemical sense, this being in stark contrast to the Mesozoic shales which are bitumen-rich. Kerogen is, therefore, the major gas precursor in the Cambrian and Silurian of the Sichuan Basin. Graptolites and solid bitumen are petrographically dominant. The solid bitumen exhibits flow structures and is deduced to be highly polar because it is insoluble in dichloromethane. Secondary cracking kinetics determined for the Arthur Creek using the GORfit Model are closely similar to source rocks containing predominantly paraffinic oil. Late gas generation from very stable refractory kerogen structures via alpha-cleavage reactions at maturities above 2% equivalent vitrinite reflectance was verified, and importantly, the upper ceiling for late gas generation in Paleozoic shales of the Sichuan Basin is set at 3% Ro. As far as the Qiongzhusi shale is concerned, raising the prospective acreage to a 3% Ro limit brings an additional contribution of 40 mg HC/g total organic carbon of late gas charge. The same is true for the extensive fairway of the Longmaxi shale along the western flank of the basin, close to the subcropping erosional edge.

Nanoindentation is a valuable tool, which enables insights into the material properties of natural, highly inhomogeneous composite materials such as shales and organic matter-rich rocks. However, the inherent complexity of these rocks and its constituents complicates the extraction of representative material parameters such as the reduced elastic modulus (Er) and hardness (H) for organic matter (OM) via nanoindentation. The present study aims to extract the representative H and Er values for OM within an over-mature sample set (1.33-2.23%Rr) from the Chinese Songliao Basin and evaluate influencing factors of the resulting parameters. This was realized by means of high-speed nanoindentation mapping in combination with comprehensive optical and high resolution imaging methods. The average Er and H values for the different particles range from 3.86 +/- 0.17 to 7.52 +/- 3.80 GPa and from 0.36 +/- 0.02 to 0.64 +/- 0.09 GPa, respectively. The results were subsequently processed by the unsupervised machine learning algorithm k-means clustering in order to evaluate representative Er and H results. The post-processing suggests that inherent heterogeneity of OM is responsible for considerable data scattering. In fact, surrounding, underlying and inherent mineral matter lead to confinement effects and enhanced Er values, whereas cracks and pores are responsible for a lowered stiffness. Adjusted for these influencing factors, a declining trend with increasing maturity (up to 1.96%Rr) could be observed for Er, with average values calculated from representative clusters ranging from 5.88 +/- 0.37 down to 4.07 +/- 0.32 GPa. Er slightly increases again between 2.00 and 2.23%Rr (up to 4.85 +/- 0.35 GPa). No clear relationship of H with thermal maturity was observed. The enhanced accuracy archived by a large data set facilitated machine learning approach not only improves further modelling attempts but also allows insights of impacting geological processes on the material parameter and general understanding of mechanical behavior of OM in rock formations. Thus, the presented multimethod approach promotes a fast and reliable assessment of representative material parameters from organic rock constituents.

The presence of solid bitumen strongly affects hydrocarbon storage and expulsion from a source rock as it might either cause blockage of pore throats leading to lower effective gas permeability, or contribute to hydrocarbon storage and provide migration pathways when a continuous network of hydrocarbon-wet organic matter (OM) pores is formed. Furthermore, organic matter transformation reactions are suggested to influence mineral diagenesis as well. In an attempt to characterize different solid bitumen types and transformation stages over a broad maturity interval (0.5–2.7%Ro) and for varying primary kerogen compositions, we reviewed optical and scanning electron microscopy (SEM) data of 35 solid bitumen-rich shale samples with a Cambrian to Triassic age. We were able to identify in-situ pre-oil solid bitumen, as well as remobilized post-oil solid bitumen at various maturity stages from the early oil window onwards. Solid bitumen is the main host for SEM-visible organic matter porosity; onset of porosity development in solid bitumen differs considerably between predominantly oil-prone (e.g., alginites, amorphous OM from algal and bacterial precursors) and gas-prone (vitrinite-rich) kerogen compositions. Furthermore, solid bitumen (pyrobitumen) in rocks with a terrestrially dominated OM composition seems to be considerably less mobile within the source rock compared to pre- and post-oil solid bitumen in oil-prone rocks, and less reactive in terms of porosity generation. In most samples, several solid bitumen populations with varying fluorescence properties and bitumen reflectance were observed, complicating the use of these petrographic maturity indicators. The apparently different solid bitumen populations often form continuous networks at the SEM-scale. Microstructural features such as irregularly distributed sponge-like porosity or detrital and authigenic mineral inclusions in the sub-micrometer scale were found to have a great influence on texture and reflectance under reflected light microscopy. The formation of authigenic minerals (quartz, various carbonate phases with different Ca/Mg/Fe proportions, magnetite in Cambrian samples) was observed frequently in post-oil solid bitumen of oil-prone rocks, indicating a close genetic relationship between transformation products formed during hydrocarbon generation (e.g., acetate, carbon dioxide and methane) and the dissolution and precipitation of minerals during diagenesis. In some cases, stylolite-like features in the sub-micrometer scale were found, showing that processes well-known from reservoir characterization at core-scale also play a role at the micrometer-scale. Furthermore, the observed strong interaction between organic matter transformation and mineral authigenesis indicates a substantial aqueous component even in pores filled apparently exclusively with solid bitumen.

The present contribution aims for a characterization of microstructure and pore-space distribution of upper Visean Rudov beds, considered the main source rock for conventional oil deposits in the Ukrainian Dneiper–Donets Basin and a prospect for unconventional hydrocarbon production in recent years. Broad ion beam–scanning electron microscopy (SEM) mapping revealed a remarkably heterogeneous microstructure controlled by diagenetic precipitates (Fe/Mg carbonates, albite). Formation of these precipitates is likely triggered by organic matter decomposition and represents an important influencing factor for overall porosity and permeability. Furthermore, shale diagenesis also influences mechanical properties, as suggested by nanoindentation tests. The SEM-visible organic matter porosity is restricted to solid bitumen; although pores less than 2–3 nm in vitrinites of overmature samples are indicated by focused ion beam–SEM results, they cannot be resolved clearly by this method. Pore generation in solid bitumen that likely formed in situ in primary amorphous organic matter already starts at the early oil window in samples from the basinal oil-prone organofacies, whereas most porous solid bitumen at peak oil maturity was interpreted as relicts of primary oil migration, representing an earlier oil phase that predominantly accumulated in quartz-rich layers and became nanoporous during secondary cracking. In the terrestrially dominated transitional to marginal organofacies, pore generation in pyrobitumen resulting from gas generation occurs significantly later and is less intense. Formation of authigenic clay and carbonate minerals within pyrobitumen is likely related to organic acids formed during bitumen decomposition and implies the presence of an aqueous phase even in pores that are apparently filled exclusively with solid bitumen.

Shallow oil and gas shows are common in the Alpine thrust front (including the Flysch Zone) and the North Alpine Foreland Basin in Switzerland, southern Germany and Austria, but have not hitherto been evaluated systematically. In the vertically-drained Vienna Basin and the easternmost part of the Flysch Zone, shallow oil and gas shows and seeps often coincide with deeper-lying hydrocarbon accumulations, and gas shows occur along major faults – for example within the urbanised area of the city of Vienna. The number of gas shows decreases in the Vienna Basin away from (to the south of) the subcrop of the main thermogenic source rock (the Upper Jurassic Mikulov Formation); however shallow accumulations of microbial gas occur in that area. To the west, along the northern margin of the laterally-drained North Alpine Foreland Basin, oil shows have been recorded in both Austria and Switzerland; microbial gas shows are common in addition to thermogenic hydrocarbons. Typically the shows form regional clusters along river valleys and occur above shallow gas accumulations. A Lower Oligocene organic-rich interval represents the main source of oil / condensate and thermogenic gas in the Upper Austrian part of the North Alpine Foreland Basin, whereas the composition of oil shows within the Calcareous Alps to the south indicates the presence of mature Mesozoic source rocks within the Alpine nappes. This implies the presence of an additional, as-yet untested petroleum system. Thermogenic gas, occurring in Permo-Triassic evaporitic rocks in the Calcareous Alps, as well as microbial gas in younger sediments, has frequently been encountered during salt mining and tunnelling activities. A surprising discrepancy has been found in different parts of the study area between the number of hydrocarbon shows and the number of economic fields. Whereas the number of fields and shows are approximately in proportion in the Vienna Basin and the Austrian sector of the North Alpine Foreland Basin, shows appear to be “under-represented” in Germany. By contrast in Switzerland, despite a high number of shows especially in the North Alpine Foreland Basin and the Jura fold-and-thrust belt, no economic production has been established to date. Future exploration will show whether this is due to poor reservoir/trap quality, or if undiscovered resources are in fact present. The presence of oil shows generated from Mesozoic and Oligocene source rocks in the SW German and Swiss parts of the North Alpine Foreland Basin suggests the occurrence of multiple petroleum systems; these systems should be delineated in future studies. Few surface seeps have been recorded in less populated parts of the study area such as the high Alps, possibly due to sampling bias. However, this bias does not explain the low frequency of recorded hydrocarbon shows in the German part of the North Alpine Foreland Basin. This may be because the geological setting there is in general less favourable for the migration of thermogenic gas into shallow reservoirs and its preservation in shallow traps.

The Ukrainian Donets Basin (Donbas) is one of the major coal mining provinces worldwide. While the depositional setting of Donbas coals is well-studied, information on modes of trace element occurrence and changes in element composition with increasing maturation is lacking. Within the frame of the present study, both major (light) elements (C, O, S) and trace elements (e.g. As, Cu, Hg, Mo, Pb) were investigated using the electron microprobe (EPMA), which allows in-situ determination of the chemical composition of a maceral or mineral phase. Deviating maturity trends in C, O and S contents were found for different maceral groups. In relatively immature samples ( 0.9%Rr), S contents of vitrinites and liptinites are comparable, but lower in inertinite macerals. Vitrinites in a marine-influenced coal host a higher amount of organic S, whereas the trace element concentrations are lower than in the investigated non-marine coals. As expected, a trend of increasing C and decreasing O contents was observed for vitrinite macerals within a maturity range from 0.5 to 1.4%Rr, referred to a decrease in volatile compounds during thermal maturation. The light element composition generally tends to higher homogenity with increasing coal rank. Highly variable trace element concentrations of ash residues were determined for Donbas coals, with measured As contents up to several thousand ppm. Despite enrichment in epigenetic pyrite, a clearly isolated inorganic source could not be identified, suggesting that trace element storage in macerals is an important factor. EPMA measurements revealed an organic matter affinity for at least part of the investigated elements (e.g. Hg, Mo, Pb).

Lacustrine oil shale is an important unconventional energy source in China. Previous exploration has mainly focused on stable deep lake deposits, whereas lacustrine oil shale layers in unstable sedimentary settings, which are widely distributed in Cretaceous strata, having received little research attention. The present paper is focused on the Aptian Jiufotang Formation in the Beipiao Basin. In order to study the impact of gravity flows and volcanism on oil shale formation, petrology, organic geochemistry, molecular geochemistry and elemental geochemistry were used to characterize the oil shales, which are very rich in well-preserved fossils (“Jehol Biota”). The predominant macerals in the high quality oil shales are lamalginite and telalginite, suggesting organic matter was derived mainly from phytoplankton and aquatic algal-bacterial organisms. A ternary diagram of C27-C28-C29 steranes showed increasing contribution of land plants in organic-lean units. Element indices such as Sr/Ba, Ca/(Ca + Fe), V/(V + Ni), δCe, Cu/Zn, Th/U, Sr/Cu, Fe/Mn, Ti/Al, TOC/S, as well as biomarker ratios (pristane/phytane, gammacerane index) and the index of compositional variability (ICV), show that high-quality oils shales were deposited under anoxic freshwater conditions. Terrigenous detrital input was low, and a warm and humid palaeoclimate, as well as a stable tectonic setting, likely prevailed. At times, low-density turbidites were accompanied by the input of terrestrial detritus, promoting a greater degree of lake oxygenation, thereby reducing oil shale potential. Volcanic eruptions triggered the occurrence of low-density turbidites due to emission of greenhouse gases which facilitated a drier climate. Periods of high-quality oil shale formation can therefore be linked to times of weak volcanism and tectonic activity, in which the organic matter was deposited under conditions of warm and humid paleoclimate, with enhanced preservation due to anoxic bottom waters in the lacustrine system. The organic-rich unit B within the Jiufotang Formation seems suitable for the application of in-situ oil shale conversion.

Various compositional, depositional and maturity related influencing factors affect the complex pore structure of coal. To study the pore structural evolution at nanoscale, a well characterized sample set of vitrinite-rich Carboniferous coals from the Ukrainian Donets Basin, covering a maturity interval from 0.69 to 1.47%Rr, was selected. Conventional bright field transmission electron microscopy (BF TEM) and high-resolution TEM (HRTEM) imaging was used to directly determine pore size distributions, pore morphology, geometry factors and other structural features, while gas invasion techniques such as low-pressure gas adsorption (CO2 and N2) were used for the investigation of micro- and mesopore structural parameters. High-pressure CH4 sorption experiments revealed changes in the methane storage capacity within the investigated maturity range, while associated structural changes of vitrinite were monitored by Raman spectroscopy. The results indicate pore occlusion in vitrinite mainly at peak oil window maturity, the sensibility of micro- and mesopore structure to thermal maturity and the importance of organic sulphur as a catalyst for kinetics of structural modification. Observed structural changes at 1.10%Rr were related to the onset of wet-gas generation. A structural control on micromechanical properties of vitrinite is indicated by the correlation between reduced elastic moduli from a previous study and average nanopore diameters obtained by HRTEM. The applied comprehensive approach improved the understanding of depositional and maturity-related processes that may affect pore evolution and resulting gas storage capacity of coals.

The Upper Jurassic Mandal Fm. of the Central Graben, Norway represents an important source rock that charged major petroleum accumulations in the North Sea, including the giant Ekofisk field. Nevertheless, exploration to date has been less successful than expected in marginal basin position such as the Cod Terrace, the Mandal High or the Sogne Basin, probably due to higher proportions of thermally stable (type III) kerogen. In an attempt to delineate changes in initial kerogen composition from later effects such as delayed expulsion of hydrocarbons, traditional organic petrography and scanning electron microscopy were combined with organic geochemical proxies and gas adsorption tests. The kerogen composition of the Mandal Fm. shows considerable variation. Samples hosting autochthonous coaly layers were found in wells from the Sogne Basin and the Cod Terrace, for which less generative potential was previously postulated. Nevertheless, samples hosting mainly vitrodetrinite were also found in basinal wells. A correlation of total organic carbon contents with liptinite percentages highlights enhanced bioproductivity or preservation efficiency for samples with abundant algal organic matter, that were likely deposited under deeper water and possibly oxygen-depleted conditions. By combining organic geochemical proxies with nitrogen sorption data, it could be proven that in case of the Mandal Fm., the (bituminous) organic matter fraction represents the controlling factor on abundance of micro- and mesopores and hence adsorptive gas retention. The amount of bitumen extractable from the Rock-Eval S2 peak (S2 bitumen ) shows a strong correlation with the total inner surface area, suggesting that small mesopores ( bitumen , which appears non-porous at SEM-scale. Furthermore, the total inner surface area decreases strongly with thermal maturity, documenting a change in pore characteristics of the organic matter fraction (growth of mesopores and occurrence of macropores) by advancing hydrocarbon generation. Pyrobitumen-rich Upper Visean reference samples at peak oil and early wet gas window maturity show intense sponge-like pyrobitumen-hosted porosity coinciding with a low relative proportion of S2 bitumen (high petroleum quality). Pyrobitumen is not affected by solvent extraction, thus not contributing high-molecular weight compounds to the extracted fraction. Such inert meso- to macroporous residues might contribute only relatively little to gas sorption capacity, but might represent important storage space for free gas, as well as flow pathways during expulsion.