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The Songliao Basin is the largest Early Cretaceous lacustrine rift basin of northeast China and hosts tremendous conventional and unconventional petroleum resources. However, the distribution of shale oil is not well constrained, as production from source rock reservoirs requires certain thermal maturity cut-offs (vitrinite reflectance of > 0.8%Rr). In this study, the thermal maturity of the Qiangshankou Formation along the Southern Uplift and in the Central Depression of the Songliao Basin was evaluated by combining traditional and advanced petrographic and geochemical maturity proxies with clay mineralogical investigations. The Qingshankou Formation is one of the major source rocks of the region, but previous studies encountered difficulties in obtaining reliable maturity data, mainly due to strongly shifted Tmax values. Equally, Tmax determined during this study showed apparent shifting likely caused either by retained solid bitumen or by variations in kerogen type. In contrast, the measured vitrinite reflectance shows a reliable depth trend, meeting the shale oil cut-off maturity of 0.8%Ro at a drilling depth of ~ 2300 m, which is only reached in the Central Depression of the basin. The vitrinite reflectance trend is supported by changes in clay mineralogy, such as the progressing ordering of I/S mixed layers (“Reichweite”), increasing illitization, decreasing detrital kaolinite and correspondingly increasing authigenic chlorite contents. Maturity-related biomarker proxies are only partly valid; while the methylphenanthrene index (MPI-1) and the trimethylnaphthalene ratio (TNR-1) show reliable maturity trends even over short depth intervals, other established proxies (e.g. based on alkylbiphenyls) proved insensitive to changes from immature to peak oil mature and are, therefore, not recommended for further use in studies on Qingshankou Fm. shales. In summary, the combination of various maturity parameters improves the understanding of shale oil distribution in the central Songliao Basin, providing valuable insights for studies on similar unconventional targets in the region.

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.

The mineralogy of Devonian to Carboniferous shales from the Ukrainian Dniepr-Donets Basin (DDB) was investigated during this study. These shales show a high compositional variability in vertical and lateral directions. Furthermore, stratigraphic trends were found to be controlled both by climatic factors as well as by changing detrital input from the hinterland. High kaolinite contents and predominance of kaolinite over illite in the Tournaisian and partly in the lower Visean units are likely a result of intense chemical weathering related to the Hangenberg climatic event at the Devonian/ Tournaisian boundary. In contrast, abnormally high kaolinite contents in upper Visean and Serpukhovian samples at the basin center might be caused by different transport properties of kaolinite and illite, leading to selective concentration of small detrital kaolinite particles, which are often in the sub-micrometer range according to scanning electron microscopy observations. K/Al elemental ratios correlate well with illite/kaolinite ratios for samples in which significant amounts of both clay minerals are present, which enables a pre-evaluation of the relative kaolinite content based on bulk geochemical data. As kaolinite is suggested to decrease the fraccability of shales and to have a great influence on their wetting behaviour, this is useful information for explorational purposes. Higher feldspar contents in Devonian and Tournaisian samples, especially along the NE basin margin and in the shallow NW part of the DDB, are likely related to increased detrital input from magmatic precursors (e.g. in the Voronezh Massif ) during (and shortly after) the active rift stage of the DDB. In general, feldspar contents are higher in proximal positions compared to the basin center, which is likely a result of shorter transport distances of the comparably large feldspar grains. Finally, the presence of expandable clay minerals down to depths of 6 km and the fact that no thermal maturity trend is visible down to these depths, proves, that a low post-depositional heat flow was present in the DDB. This is in good agreement with vitrinite reflectance measurements and thermal modelling results from previous studies, which suggest a low Mesozoic heat flow.

This study aims to understand the origin of giant magnesite and talc deposits in the Liaohe Group (Liaoning Province, NE China). Magnesite stromatolites and the composition of fluid inclusions suggest that magnesite or high-Mg calcite precipitated directly from strongly restricted seawater pools with meteoric influx. A primary evaporitic origin is also indicated for parts of the investigated dolomites by comparably heavy δ18O values. Later, intense metasomatic activity led to the formation of a magnesite/dolomite succession with irregular contacts and a lighter isotopic signature of oxygen. A slight shift in δ18O to more positive values was observed for talc-hosting magnesite, which can be explained by the incorporation of isotopically light oxygen into talc. This highlights that the hydrothermal processes that led to talc formation influenced the hosting carbonates as well, which is also documented by a tendency to smaller crystal sizes, a higher whiteness and lower trace element concentrations in samples from locations nearby large talc bodies. Although δ13C is suggested to be less sensitive to hydrothermal activity, comparably light δ13C values were determined for magnesite sinters, as well as for remobilized magnesites. In general, the δ13C signature of the investigated magnesites is lighter than expected for Proterozoic carbonates. A single-stage generation of the giant talc deposit in the study area is suggested based on elemental and isotopic data. Later deformation led to a (iso-chemical) re-location of talc at least once. During this process, irregularly distributed, cloudy/massive talc bodies acted as weak zones and were incorporated into shear bands up to several meters in thickness, which form the actually present, structurally controlled deposit. The original ore type is preserved only in areas with minor deformation. Lamprophyre dykes prove Jurassic volcanism and are clearly younger than the main phase of talc generation. A younger (post-Jurassic?), intense tectonic event is indicated by strongly tectonized dyke material that is re-worked into strike-slip faults and shows siliceous contact zones to the surrounding magnesite. These faults occasionally cross-cut the older, deposit-forming talc shear bands, indicating that the event that led to the deformation of lamprophyre dykes was younger than the main phase of talc re-location. However, this younger event did not lead to a second phase of major talc generation or affect the quality of the initial deposit to a large extent.

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 Songliao Basin is an important hydrocarbon province of Northeastern China and has a long history of conventional oil and gas production. Nowadays, unconventional resource estimation becomes increasingly important and particularly shale oil/gas production from mature source rocks in the Central Depression may be of great relevance for the regional exploration strategy. The Qingshankou Formation is a promising source rock reservoir. However, for shale oil/gas production to be successful, a refined understanding of the distribution of hydrocarbons within the low-permeable rocks, as well as the timing of hydrocarbon expulsion and its linkage to changing pore characteristics, are key requirements. Therefore, a multi-analytical geochemical and porosity study was conducted on a set of 12 oil-prone, alginite-rich samples from a depth range from 200 to 2500 m in order to understand the linkage of burial compaction, hydrocarbon generation and pore evolution. Macro- (>50 nm) and mesopores (2–50 nm) were investigated by a combination of nitrogen gas adsorption/desorption measurements at 77 K and broad ion beam – scanning electron microscopy. The adsorption tests were conducted on samples before and after solvent-extraction in order to study the effects of soluble organic matter (OM) on pore distributions. These data were compared with organic petrographical observations, bulk geochemical parameters before and after extraction, as well as extract yields from the bulk source rock in order to link structural and geochemical changes in the interval from immature to late peak oil mature (0.4–0.9 %Rr). Total SEM-visible macro- and mesoporosity (φBIB) is generally limited, but a weak trend of total φBIB with quartz contents indicates the importance of brittle minerals for pore preservation. A depth trend towards smaller average pore sizes, higher pore aspect ratios, as well as preferentially bedding-parallel pore orientations reflects burial compaction. An observable deficiency of pores 0.8 %Rr, corresponding with a decrease in the differential BJH volume and less visible pre-oil solid bitumen. The gas storage and retention behavior of the investigated shales may abruptly change with ongoing thermal maturation, as matrix pores are liberated from occluding hydrocarbons.

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).

Upper Visean Rudov Beds (V-23) are considered as one of the main source rocks within the northwestern Dniepr Donets Basin (DDB). Average TOC values within the Srebnen Bay (northwestern DDB) exceed 4% (thickness up to 100 m). Average TOC contents north and northwest of the Srebnen Bay (up to 60 m) are significantly lower (2–4%) but still sufficient for unconventional hydrocarbon production, whereas wells along the northeastern basin margin do not hold a shale oil/gas potential ( 5.5 km. Although hydrogen index (HI) values of the most immature samples are ≤300 mgHC/gTOC, basinal Rudov Beds host a potential to generate Paraffinic-Naphthenic-Aromatic (P-N-A) low wax oil according to pyrolysis experiments. A basinward maturity trend is visible, but the maturity cut-offs for shale oil/gas production (>0.8%Rr/>1.2%Rr) are reached at great depths (>4.5 km/5.5 km) only. Furthermore, results of kinetic experiments do not argue for presence of type IIS kerogen potentially triggering earlier hydrocarbon generation. The mineralogy of Rudov Beds varies strongly in lateral and vertical directions, limiting the predictability of mechanical behaviour. Samples from the siliceous (basinal) facies partly contain more than 60% of brittle minerals (quartz, feldspar, carbonates, etc.) suggesting a good fraccability. This value is rarely reached by samples from the transitional and lagoonal (calcareous and clayey) facies. The clay mineral fraction within many investigated Rudov samples is dominated by kaolinite, which is suggested to diminish the fraccability of shales. Apart from that, expandable clay minerals (ECM) are present in samples from more than 5 km depth, a result of low Mesozoic heat flow.

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.

This study applied a multianalytical approach to identify active early diagenetic processes during deposition of the Lower Jurassic Bachental bituminous marls (Western Tethys realm). Results point to a major redox control on organic matter (OM) preservation and early diagenetic modifications. Whereas Mn reduction was the main OM oxidation process causing a maximum OM loss of ~1.5% and a lowering of hydrogen index values by up to 400 mgHC/gTOC under suboxic conditions, sulfate reduction was the dominant degradation process under anoxic-euxinic conditions. OM oxidation processes caused an increase of pH values (up to >9) and alkalinity in pore waters. These changes initiated carbonate precipitation in all samples, with high Mn-contents and predominant kutnohorite mineralization in suboxic layers, and presence of Mn-bearing calcite in anoxic units. The actual occurrence of the distinct carbonate phases (dolomite, kutnohorite, Mn-bearing calcite and siderite) reflects the redox pattern established by previous studies. Dissolution of biogenic silica and incipient alteration of pyrite in response to changing pore water pH and alkalinity conditions was found limited to the anoxic-euxinic intervals. In summary, this study provides detailed insights into the early diagenesis of organic-rich marls in a semi-restricted basin setting under varying oxygen depletion.

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.