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Mudstones and shales are fine-grained sedimentary rocks that can serve as top seals of geological reservoirs in various geoenergy applications. Apart from traditional oil and gas exploration, the urgent need for underground storage of energy carriers (e.g., H2) and climate-relevant gases (e.g., CO2) facilitated extensive research on pore structural and mechanical parameters and their influence on the seal capacity of these rocks. The fracture behaviour of mudstone seal rocks controls the risk of seal failure due to microfracturing as a response to various geological processes (e.g., buoyancy pressure from the reservoir). In this contribution, the high-speed nanoindentation mapping approach was carried out for a proven mudstone top seal sample (~1629 m; quartz 31%, clay mineral 39%) from a Vienna Basin oil field. The nanoindentation results were then post-processed with machine learning-based tools to obtain representative mechanical parameters of the clay matrix. k-means clustering analysis was performed using three input features including hardness (H), reduced elastic modulus (Er), and the elastic-plastic deformation ratio based on the obtained load-displacement curves. In addition, broad ion beam-scanning electron microscopy (BIB-SEM) maps were taken before and after the nanoindentation to correlate the indentation results with direct imaging information and to verify the k-means clustering results. A total of 8 indentation map arrays (7 × 7 indents) were placed to test the sensitivity of different tips to indentation depth and load rate. The comparison of BIB-SEM image data and k-means clustering showed that decisions on phase assignment can be significantly improved and performed in a shorter time by k-means clustering analysis, still showing an overall good agreement with manual selections. For the studied mudstone sample, the resulting average Er and H values of the clay matrix range at 17.58 ± 6.89 GPa and 0.63 ± 0.76 GPa (n=30), respectively for the Berkovich tip and at 15.03 ± 4.79 GPa and 0.38 ± 0.23 GPa (n=62), respectively for the Cube Corner tip. The testing with both tips shows that despite the strongly heterogeneous microstructure of the indented clay matrix the obtained mechanical parameters are not sensitive to indentation depths and hence representative values can be determined from minimum volumes with statistical significance. Nevertheless, compared with the Berkovich tip, the Cube Corner tip sampled deeper depths (58-443 nm for the Berkovich tip and 412-1747 nm for the Cube Corner tip) and introduced more surface damage. By increasing the load rate from 1000 to 6000 μN s−1, the indentation testing tended to be unstable and the surface showed strong damage at the highest load rate. In conclusion, this contribution represents an important methodological step towards the implementation of combined high-speed nanoindentation mapping and machine learning data analysis as a feasible high throughput tool for the mechanical characterization of mudstones and similar fine-grained sedimentary rocks. The presented approach is planned to be applied to an extensive set of mudstone samples from the Vienna Basin with the purpose to link mechanical property changes to burial diagenesis.

Both the primary mineral composition and secondary diagenetic processes may affect shale reservoir characteristics such as effective porosity, pore throat distribution, resulting permeability, wettability, etc. Hence, a better understanding of shale diagenesis is key to the prediction of shale oil and gas resource potential. The first member of the Qingshankou Formation (K2qn1) in the northern part of the Songliao Basin is an organic-rich shale with great source potential. Attempting to characterize the influence of different diagenetic processes active in the clay mineral-rich formation on pore space evolution, 19 sample from the K2qn1 interval (vitrinite reflectance from 0.55 to 1.58 %Ro) were selected and investigated by optical and scanning electron microscopy (SEM). This maturity window covers the hydrocarbon generative and expulsion stages and hence allows to reconstruct the processes active during organic matter (OM) transformation. Interactions of inorganic mineral grains with products of the transformation products of lamalginite-dominated primary OM (i.e., soluble bitumen) and associated pore space changes could be observed at various maturity stages. SEM visible authigenic quartz is present from the oil window up to the dry gas window, mostly in the form of submicron (nm-μm) size microcrystals embedded in the interparticle pores between clay minerals. Euhedral and subhedral quartz types are occasionally visible in mineral dissolution pores and OM-hosted pores associated with post-oil solid bitumen. Authigenic clay minerals (such as chlorite) are visible along the whole maturity range, but predominantly form in interparticle and OM-hosted pores at maturity levels >1.1 %Ro. Solid bitumen impregnations are often associated with authigenic minerals, forming rims along crystal boundaries. This indicates that the mineral precipitation may be associated with fluid compositional changes which occur during hydrocarbon generation (e.g., formation of water-soluble organic acids, etc.). According to the SEM observations, clay mineral-associated interparticle pores are the main storage space for bitumen in the K2qn1 source rock reservoir. These pores may be occluded at early to peak oil window maturity and re-opened at post-oil window maturity due to the expulsion of main parts of the generated hydrocarbons (pyrobitumen stage). This highlights that hydrocarbon generation and expulsion are key factors in porosity development both with respect to organic (bitumen generation) and inorganic (e.g., authigenic quartz precipitation) transformation reactions.

The Toarcian oceanic anoxic event (T-OAE) is associated with a prominent negative carbon isotope excursion (CIE; ~ 183 million years (Myr)). About 10-m-thick organic matter-rich sediments accumulated during the T-OAE in the Southwest German Basin (SWGB). Rock–Eval, maceral and biomarker analysis were used to determine variations of environmental conditions across the CIE interval. Carbon isotope records were determined for various n-alkanes, pristane and phytane to contribute to the reconstruction of the paleo-environment and to study the factors controlling molecular δ13C values. Geochemical redox indicators provide evidence for photic zone anoxia during the Toarcian CIE, which reached its maximum after deposition of the “Unterer Stein” marker horizon. The 2α-methylhopane index suggests enhanced activity of diazotrophic cyanobacteria, which is also supported by nitrogen isotope data. This distinguishes the SWGB from other basins with Toarcian black shale. Oxygen-depleted conditions, albeit with lower intensity continued after the CIE. All investigated compounds replicate the negative CIE, but the magnitudes vary considerably. The largest shift is observed for n-C27 (9‰) and reflects the combined effect of the global CIE and a major change in organic matter input (termination of terrigenous organic matter input). The shift for short-chain n-alkanes, pristane, and phytane, interpreted to reflect marine biomass, varies between 4.5 and 5.0‰. This is the highest value observed so far for any Toarcian section. δ13C values of pristane and phytane reach a minimum near the base of the CIE interval and increase upsection. Thus, the maximum negative isotope shift predates the strongest basin restriction by about 450 thousand years (kyr).

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 Franconian Alb of SE Germany is characterized by large-scale exposures of Jurassic shallow marine limestones and dolostones, which are frequently considered to be outcrop analogues for deep geothermal reservoir rocks in the North Alpine Foreland Basin farther south. However, the burial history of the Franconian Alb Jurassic strata is not well known as they were affected by emersion, leading to extensive erosion and karstification with only remnants of the original Cretaceous and Cenozoic cover rocks preserved. To estimate the original thicknesses of the post-Jurassic overburden we investigated the petrophysical properties and the thermal history of Lower and Middle Jurassic mudstones to constrain their burial history in the Franconian Alb area. We measured mudstone porosities, densities, and maturities of organic material and collected interval velocities from seismic refraction and logging data in shallow mudstone-rich strata. Mudstone porosities and P-wave velocities vertical to bedding were then related to a normal compaction trend that was calibrated on stratigraphic equivalent units in the North Alpine Foreland Basin. Our results suggest maximum burial depths of 900–1700 m, 300–1100 m of which is attributed to Cretaceous and younger sedimentary rocks overlying the Franconian Alb Jurassic units. Compared to previous considerations this implies a more widespread distribution and increased thicknesses of up to ∼900 m for Cretaceous and up to ∼200 m for Cenozoic units in SE Germany. Maximum overburden is critical to understand mechanical and diagenetical compaction of the dolostones and limestones of the Upper Jurassic of the Franconian Alb. The results of this study therefore help to better correlate the deep geothermal reservoir properties of the Upper Jurassic from outcrop to reservoir conditions below the North Alpine Foreland Basin. Here, the Upper Jurassic geothermal reservoir can be found at depths of up to 5000 m.

With the rising potential of underground hydrogen storage (UHS) in depleted oil and gas reservoirs or deep saline aquifers, questions remain regarding changes to geological units due to interaction with injected hydrogen. Of particular importance is the integrity of potential caprocks/seals with respect to UHS. The results of this study show significant dissolution of calcite fossil fragments in claystone caprock proxies that were treated with a combination of hydrogen and 10 wt% NaCl brine. This is the first time it has been experimentally observed in claystones. The purpose of this short communication is to document the initial results that indicate the potential alteration of caprocks with injected hydrogen, and to further highlight the need for hydrogen-specific studies of caprocks in areas proposed for UHS.

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 (

Since 1950, when the megascale Shebelinka deposit was found in the north-eastern portion of the Dnieper-Donets basin (DDB) this district has been served as a heartland of the hydrocarbon extraction in Ukraine. Right now, this area is again facing a new wave of commercial interest. Most conventional hydrocarbon plays here contain natural gas and liquid gas accumulated in numerous clastic and fractured horizons throughout Carboniferous to Lower Permian successions. The numerical basin modelling in the Donbas segment indicated that organic-rich sediments are thermally mature in the deep levels of the basin. Our interpretation of the structural patterns within the study area suggests that the kinematic development of the fracture sets is consistent with the model of development of subsidiary structures within the dextral strike-slip zone. Nearly all gas and gas condensate fields in the eastern part of the DDB may be classified as naturally fractured reservoirs in fault-breached anticlinal traps associated with releasing jogs in strike-slip assemblages. Gaseous hydrocarbons generated in deep "gas window" compartments have escaped here via several fracture corridors forming "sweet spots " sites. The main objective of this contribution is to get an insight into the style and structural trends of formation structural traps of hydrocarbons which in concert with basin modeling technologies will ensure proper technical decisions for the efficient exploration and production of gas reservoirs. This research summarizes new insights into gas deposits formation in the eastern part of DDB based on a synthetic approach ascertaining a vital connection of basin modeling results with the spatial distribution of kinematically induced releasing jogs which facilitating magnified fluid-and-gas conductivity.

A shale lithofacies scheme is commonly used to characterize source rock reservoirs of the Lower Cambrian Niutitang Formation. However, this classification ignores that individual components such as quartz may have different origins, potentially affecting reservoir quality. The main objective of this article is, therefore, to present a refined scheme for lithofacies and an image processing workflow for the detection of quartz types in the Niutitang Formation shales from the Jiumen outcrop in the Guizhou Province (Upper Yangtze Basin, SW China). In order to do so, a combination of bulk density, optical and scanning electron microscopy and image analysis was used. The shale lithology was macroscopically classified into seven major categories and nineteen subcategories. Subsequently, the shales were investigated at the microscopic level, mainly focusing on quartz types and microstructural variations. Afterwards, the workflow to calculate the weight per unit volume (1 cm3) of the quartz types was presented, i.e., firstly, by calculating the weight of mineral matter by subtraction of the measured weight of organic matter from the bulk shale; secondly, by calculating the weight of total quartz in bulk shale from the weight of mineral matter and its proportion calculated from X-ray diffraction data; thirdly, by calculating the weight of detrital quartz and non-detrital quartz with energy dispersive X-ray mapping, image processing and quartz density; finally, by calculating the weight of clay-sized quartz by subtracting of the weight of detrital and non-detrital quartz from the weight of the total quartz. The bulk quartz content was found to be dominated by clay-sized quartz, which may mainly control the mesopore volume available for gas storage and, hence, the shale gas reservoir development.

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.

Purpose To investigate the natural history and genetic associations of drusenoid pigment epithelial detachment (DPED) associated with age-related macular degeneration (AMD). Design Retrospective analysis of a prospective cohort study. Participants Of the 4203 Age-Related Eye Disease Study 2 (AREDS2) participants, 391 eyes (325 participants) had DPED without late AMD at the time of DPED detection. Genetic analyses included 120 white AREDS2 participants and 145 Age-Related Eye Disease Study (AREDS) participants with DPED. Methods Baseline and annual stereoscopic fundus photographs were graded centrally to detect DPED, a well-defined yellow elevated mound of confluent drusen ≥433 μm in diameter, and to evaluate progression rates to late AMD: geographic atrophy (GA) and neovascular (NV)-AMD. Five single nucleotide polymorphisms (CFH [rs10611670], C3 [rs2230199], CFI [rs10033900], C2/CFB [rs114254831], ARMS2 [rs10490924]) and genetic risk score (GRS) group were investigated for association with DPED development. Kaplan–Meier analyses and multivariable proportional hazard regressions were performed. Main Outcome Measures Progression rates to late AMD and decrease of ≥3 lines in visual acuity (VA) from the time of DPED detection; association of rate of DPED development with genotype. Results Mean (standard deviation [SD]) follow-up time from DPED detection was 4.7 (0.9) years. DPED was associated with increased risk of progression to late AMD (hazard ratio [HR], 2.36; 95% confidence interval [CI], 1.98–2.82; P Conclusions This study replicates the results of previous natural history studies of eyes with DPED including the high rates of progression to late AMD and vision loss (regardless of progression to late AMD). The genetic associations are consistent with genes associated with AMD progression.

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.

Purpose To analyze the prevalence, incidence, and clinical characteristics of eyes with geographic atrophy (GA) in age-related macular degeneration (AMD), including clinical and genetic factors affecting enlargement. Design Prospective cohort study within a controlled clinical trial. Participants Age-Related Eye Disease Study 2 (AREDS2) participants, aged 50–85 years. Methods Baseline and annual stereoscopic color fundus photographs were evaluated for GA presence and area. Analyses included GA prevalence and incidence rates, Kaplan-Meier rates, mixed-model regression, and multivariable analysis of the square root of GA, area adjusted for covariates, including clinical/imaging characteristics and genotype. Main Outcome Measures (1) Presence or development of GA; (2) change in the square root of GA area over time. Results At baseline, 517 eyes (6.2%) of 411 participants (9.8%) had pre-existing GA (without neovascular AMD), with the following characteristics: 33% central, 67% noncentral; and the following configurations: 36% small, 26% solid/unifocal, 24% multifocal, 9% horseshoe/ring, and 6% indeterminate. Of the remaining 6530 eyes at risk, 1099 eyes (17.3%) of 883 participants developed incident GA without prior neovascular disease during mean follow-up of 4.4 years. The Kaplan-Meier rate of incident GA was 19% of eyes at 5 years. In eyes with incident GA, 4-year risk of subsequent neovascular AMD was 29%. In eyes with incident noncentral GA, 4-year risk of central involvement was 57%. GA enlargement rate (following square root transformation) was similar in eyes with pre-existing GA (0.29 mm/year; 95% confidence interval 0.27–0.30) and incident GA (0.28 mm/year; 0.27–0.30). In the combined group, GA enlargement was significantly faster with noncentrality, multifocality, intermediate baseline size, and bilateral GA (P Conclusions Analyses of AREDS2 data on natural history of GA provide representative data on GA evolution and enlargement. GA enlargement, which was influenced by lesion features, was relentless, resulting in rapid central vision loss. The genetic variants associated with faster enlargement were partially distinct from those associated with risk of incident GA. These findings are relevant to further investigations of GA pathogenesis and clinical trial planning.

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 Dniepr-Donets Basin (DDB) hosts a multi-source petroleum system with more than 200 oil and gas fields, mainly in Carboniferous clastic rocks. Main aim of the present study was to correlate accumulated hydrocarbons with the most important source rocks and to verify their potential to generate oil and gas. Therefore, molecular and isotopic composition as well as biomarker data obtained from 12 oil and condensate samples and 48 source rock extracts was used together with USGS data for a geological interpretation of hydrocarbon charging history. Within the central DDB, results point to a significant contribution from (Upper) Visean black shales, highly oil-prone as well as mixed oil- and gas-prone Serpukhovian rocks and minor contribution from an additional Tournaisian source. Devonian rocks, an important hydrocarbon source within the Pripyat Trough, have not been identified as a major source within the central DDB. Additional input from Bashkirian to Moscovian (?) (Shebelinka Field) as well as Tournaisian to Lower Visean rocks (e.g. Dovgal Field) with higher contents of terrestrial organic matter is indicated in the SE and NW part, respectively. Whereas oil–source correlation contradicts major hydrocarbon migration in many cases for Tournaisian to Middle Carboniferous reservoir horizons, accumulations within Upper Carboniferous to Permian reservoirs require vertical migration up to 4000 m along faults related to Devonian salt domes. 1-D thermal models indicate hydrocarbon generation during Permo-Carboniferous time. However, generation in coal-bearing Middle Carboniferous horizons in the SE part of the basin may have occurred during the Mesozoic.

Objective To determine if physicians trained in ultrasound interpretation perceive a difference in image quality and usefulness between Extended Focused Assessment with Sonography ultrasound examinations performed at bedside in a hospital vs. by emergency medical technicians minimally trained in medical ultrasound on a moving ambulance and transmitted to the hospital via a novel wireless system. In particular, we sought to demonstrate that useful images could be obtained from patients in less than optimal imaging conditions; that is, while they were in transport. Methods Emergency medical technicians performed the examinations during transport of blunt trauma patients. Upon patient arrival at the hospital, a bedside Extended Focused Assessment with Sonography examination was performed by a physician. Both examinations were recorded and later reviewed by physicians trained in ultrasound interpretation. Results Data were collected on 20 blunt trauma patients over a period of 13 mo. Twenty ultrasound-trained physicians blindly compared transmitted vs. bedside images using 11 Questionnaire for User Interaction Satisfaction scales. Four paired samples t-tests were conducted to assess mean differences between ratings for ambulatory and base images. Conclusion Although there is a slight tendency for the average rating across all subjects and raters to be slightly higher in the base than in the ambulatory condition, none of these differences are statistically significant. These results suggest that the quality of the ambulatory images was viewed as essentially as good as the quality of the base images.

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.

Siliciclastic reservoir rocks of the North Alpine Foreland Basin were studied focusing on investigations of pore fillings. Conventional oil and gas production requires certain thresholds of porosity and permeability. These parameters are controlled by the size and shape of grains and diagenetic processes like compaction, dissolution, and precipitation of mineral phases. In an attempt to estimate the impact of these factors, conventional microscopy, high resolution scanning electron microscopy, and wavelength dispersive element mapping were applied. Rock types were established accordingly, considering Poro/Perm data. Reservoir properties in shallow marine Cenomanian sandstones are mainly controlled by the degree of diagenetic calcite precipitation, Turonian rocks are characterized by reduced permeability, even for weakly cemented layers, due to higher matrix content as a result of lower depositional energy. Eocene subarkoses tend to be coarse-grained with minor matrix content as a result of their fluvio-deltaic and coastal deposition. Reservoir quality is therefore controlled by diagenetic clay and minor calcite cementation.Although Eocene rocks are often matrix free, occasionally a clay mineral matrix may be present and influence cementation of pores during early diagenesis. Oligo-/Miocene deep marine rocks exhibit excellent quality in cases when early cement is dissolved and not replaced by secondary calcite, mainly bound to the gas–water contact within hydrocarbon reservoirs.