The Neogene Rioni and Kura foreland basins in Georgia are located between the converging Greater and Lesser Caucasus fold‐and‐thrust belts. The Rioni Basin continues westward into the Black Sea whereas the Kura Basin extends eastward into Azerbaijan and the Caspian Sea. “Pre‐” and “post‐salt” petroleum systems are distinguished in the Rioni Basin separated by an Upper Jurassic evaporite succession of regional extent. The pre‐salt petroleum system in the northern Rioni Basin is still poorly understood. Bathonian shales have generated oil which has been recorded in Middle Jurassic sandstones. However, as the origin of the oil in Upper Jurassic sandstones (e.g. at the Okumi oil discovery) is still problematic, the pre‐salt petroleum system remains poorly constrained. Gas‐rich, high volatile bituminous coals of Bathonian age may represent a CBM play.The post‐salt petroleum system in the Rioni Basin is charged by two prolific source rock units: the Middle Eocene Kuma Formation and the Oligo‐Miocene Maikop Group. The petroleum potential of the Kuma Formation, which is about 40 m thick, is classified as good to very good. The Oligocene part of the Maikop Group is several hundred metres thick and contains source rocks with up to 5 wt.% TOC in its lower part. Additional source rocks are present in Cretaceous and lower Paleogene levels. Oil is produced from fractured Upper Cretaceous carbonates in anticlinal structures below the Neogene unconformity and from Mio‐Pliocene siliciclastics in fault‐related anticlines. Trap formation and hydrocarbon accumulation is interpreted to have occurred since Maeotian time. Proven oil reserves are very low (∼2 million tons) and suggest low charge efficiency.Several stratigraphic horizons containing potential source rocks are present in the Kura Basin of eastern Georgia. Although oil‐source correlations have yielded unsatisfactory results, the Maikop Group is the most likely source rock, despite its relatively poor petroleum potential which is at best “fair” in the Tbilisi area in the west of the basin. Additional potential source rocks include Middle and Upper Eocene shales. Fractured Middle Eocene volcaniclastic rocks are the best producing reservoirs for hydrocarbons, but oil accumulations are also found in fractured Upper Cretaceous carbonates and in Lower and Upper Eocene, Oligocene and Neogene siliciclastics. Biomarker data suggest a Cenozoic (or Upper Cretaceous) source rock containing abundant terrigenous organic matter. Anticlines and positive flower structures related to compressional tectonics in front of the Greater and Lesser Caucasus fold‐and‐thrust belts form the main trap types. Samgori‐Patardzeuli‐Ninotsminda in the Tbilisi region is by far the largest oil field in Georgia and accounts for nearly 90% of the cumulative production of the country (28.5 million tons). The field was probably charged from a kitchen area located to the north. Strike‐slip faults played a major role as migration pathways. Despite of the presence of many oil seeps, proven reserves in the Georgian part of the Kura Basin are very low (2.4 million tons). This may reflects the presence of traps with poor seal integrity.

This study applied a multianalytical approach to identify active early diagenetic processes during deposition of the Lower Jurassic Bächental 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.

Main objectives of the present study are to define oil families and to contribute to oil-source correlations. To reach the goal, stable carbon isotope ratios (C) of individual n-alkanes and iso-alkanes (“compound specific isotopy”; CSI) have been determined together with biomarker proxies from 30 oil fields and oil shows (see Fig. 1). In addition, the most important Mesozoic and Oligocene source rock units were investigated and are briefly described below.

In Iran, almost all major travertine deposits with NW–SE trend are exposed in Urumieh-Dokhtar volcano-plutonic belt. In this study, morphology of travertine, source of CO2, and classification of travertine were investigated using geochemistry of carbon dioxide, stable carbon and oxygen isotopic analysis, SEM images and thin sections. Morphology of travertine in the study area includes mound and cascade. Stable carbon and oxygen isotope values of the north Urumieh-Dokhtar volcano-plutonic belt travertines range between 1.46 and 11.71‰ (VPDB) and − 6.08 and − 10.21‰ (VPDB), respectively. The high δ13C values suggest a contribution of CO2 liberated by thermometamorphic decarbonation besides its magmatic origin. Consequently, these travertines are classified as belonging to the thermogene category. A probable reason for the observed high carbon isotope composition in these deposits may be CO2 consumption as suggested by the presence of bacteria and diatom activities, verified by SEM images. Pisoid, crystalline crust and pebbly lithofacies were observed. The stable isotope compositions were compared to travertines around the world. Similarities in lithofacies and morphology exist between northern Urumieh-Dokhtar volcano-plutonic belt and travertines of Turkey and Spain. The Iranian travertines are located in areas with volcanic activity. Obviously, the geothermal system remained active throughout the late Quaternary to present.

This study investigates the hydrocarbon potential of Oligocene–Miocene shales in the Menilite Formation, the main source rock in the Ukrainian Carpathians. The study is based on the analysis of 233 samples collected from outcrops along the Chechva River in western Ukraine in order to analyse bulk parameters (TOC, Rock‐Eval), biomarkers and maceral composition.In Ukraine, the Menilite Formation is conventionally divided into Lower (Lower Oligocene), Middle (Upper Oligocene) and Upper (Lower Miocene) Members. The Early Oligocene and Early Miocene ages of the lower and upper members are confirmed by new nannoplankton data. The Lower Menilite Member is approximately 330 m thick in the study area and contains numerous chert beds and turbidite sandstones in its lower part together with organic‐rich black shales. The shales have a high content of silica which was probably derived from siliceous micro‐organisms. The TOC content of the shales frequently exceeds 20 wt.% and averages 9.76 wt.%. HI values range between 600 and 300 mgHC/gTOC (max. 800 mgHC/gTOC). The Middle Member contains thin black shale intervals but was not studied in detail. The Upper Member is about 1300 m thick in the study area and is composed mainly of organic‐rich shales. Chert layers are present near the base of the Member, and a prominent tuff horizon in the upper part represents a volcanic phase during shale deposition. The member grades into overlying molasse sediments. The average TOC content of the Upper Menilite succession is 5.17 wt.% but exceeds 20 wt.% near its base.Low Tmax and vitrinite reflectance measurements for the Lower (419°C and 0.24–0.34 %Rr, respectively) and Upper (425°C and 0.26–0.32 %Rr, respectively) Menilite Member successions indicate thermal immaturity. Biomarker and maceral data suggest a dominantly marine (Type II) organic matter input mixed with varying amounts of land‐plant derived material, and indicate varying redox and salinity conditions during deposition.Determination of the Source Potential Index (SPI) shows that the Menilite Formation in the study area has the potential to generate up to 74.5 tons of hydrocarbons per m2. The Chechva River outcrops therefore appear to have a significantly higher generation potential than other source rocks in the Paratethys realm. These very high SPI values for the Menilite Formation may explain why a relatively small area in Ukraine hosts about 70% of the known hydrocarbon reserves in the northern and eastern Carpathian fold‐thrust belt.

The Vienna Basin, a major petroleum province in Central Europe, hosts hydrocarbons in stacked carbonate and siliciclastic reservoirs. The study of 84 oil and 51 gas samples in the Austrian sector yields new insights into the petroleum system. The Upper Jurassic Mikulov and Falkenstein formations are the only significant source rocks, which generated oil between 0.7 and 1.0%Rr, and gas between 1.1 and 1.6%Rr. Microbial gas prevails in the southern part of the basin. Biodegradation affects oil down to a depth of 2000 m. Miocene reservoirs in the hanging wall of major faults and oils in transgressive sands are more prone to biodegradation than footwall flysch reservoirs and oils in turbiditic sands in structuralstratigraphic traps. Anaerobic biodegradation results in the formation of isotopically heavy CO2 and isotopically light (secondary) microbial methane. Hydrocarbons in deep carbonate reservoirs are affected by thermochemical sulphate reduction (TSR). While TSR-affected gas is rich in H2S and CO2, TSR-affected oil is characterized by increased dibenzothiophene/ phenantrene (DBT/Ph) ratios. In clastic reservoirs, H2S is removed by pyrite precipitation, whereas DBT/Ph ratios remain high. Hence, high DBT/Ph ratios may be used as proxy for TSR. Stable sulphur isotopes signatures confirm Upper Triassic anhydrites as the main sulphur source for H2S.

For over a century, oil has been produced in Georgia from oilfields located in the foreland basins between the Greater and Lesser Caucasus foldbelts. To date, little information on the associated source rocks has been available. In this context, this paper presents a study of 380 samples of Eocene (Kuma Formation) and Oligocene to Lower Miocene (Maikop Group) source rocks from three outcrop sections in the Rioni and Kura Basins. The Kuma Formation in the Rioni Basin is composed of fully‐marine marls and is about 40 m thick. At the Martivili and Khobi sections, the formation is thermally immature and has an average TOC of 3.2 wt%. The hydrogen indices (HI) of 300–600 mg HC/g TOC indicate that the organic matter is oil‐prone Type II kerogen. The oil generation potential is between 1.0 and 2.4 t HC/m2, and the Kuma Formation is therefore interpreted as a prolific source rock.The Maikop Group in the Rioni Basin was studied at the Martvili section, where it is thermally immature. The Oligocene succession is divided by calcareous shales deposited during the Solenovian Event (at the onset of nannoplankton zone NP23) into Pshekhian and Solenovian‐to‐Kalmykian intervals. The Pshekhian interval (NP21‐22) is over 60 m thick and comprises a marly lower part and a shale‐rich upper part, and contains high quantities (average 2.7 wt% TOC) of Type II‐III kerogen (average HI: 278 mg HC/g TOC). The overlying largely carbonate‐free shale succession, 424 m thick, is less organic matter ‐rich (∼2.0 %TOC) and contains dominantly Type III kerogen (average HI: 140 mg HC/g TOC). In total, the Maikop Group has a generation potential of about 4 t HC/m2, a value which is higher than in most other sub‐basins in the Eastern Paratethys. Because the Rioni Basin continues westwards into the Black Sea, these results are relevant for future exploration in the eastern part of the Black Sea Basin.The Maikop Group in the western Kura Basin in the Tbilisi area is over 3500 m thick and includes numerous sandstone beds. Because of the great thickness of the Maikop Group and the presence of about 3 km of overburden, which was removed during Miocene to Recent unroofing, potential source rocks in the Eocene to Lower Oligocene succession have reached oil window maturities but their hydrocarbon potential is low.

Although a number of significant oil and gas discoveries have been made within the Western Black Sea and the surrounding area, only sparse data about migration mechanisms are available. In this paper, biomarker and isotope data from five oilfields and one oil show located offshore Bulgaria and Romania (in the western Black Sea), and from one field onshore Georgia (at the margin of the eastern Black Sea), were compared with geochemical data from potential source rock intervals from borehole samples. The source rock data came from offshore Bulgaria and outcrop samples from onshore Georgia. The biomarker data indicates that all the oils analysed were generated by source rocks of Late Cretaceous or Cenozoic age. In the Western Black Sea sub‐basin, the most likely source rocks are Oligocene to Lower Miocene shales of the Maikop Group. Compound‐specific isotope data indicate that Lower Oligocene source rocks are the most significant although a contribution by Lower Miocene diatom‐rich source rocks cannot be excluded. For an oil sample from the Shromisubani field onshore Georgia, isotope data from individual n‐alkanes together with biomarker data indicates that the oil contains a mixture of hydrocarbons generated from the Middle Eocene Kuma Formation and the Oligocene part of the Maikop Group.Oligocene and Miocene source rocks are immature at the shelfal locations where the oil samples were recovered. Charge for these hydrocarbon accumulations is interpreted to have been provided by long‐distance lateral migration from source kitchens in more central parts of the Black Sea basin, where Oligocene and (some) Miocene source rocks are within the oil and gas window. The results of this study highlight the prospectivity of recently‐discovered deep‐water plays, and significantly de‐risk future deep‐water projects within the Black Sea area.

The Qorveh-Takab travertines, which are connected to thermal springs, are situated in the northwest of the Sanandaj-Sirjan metamorphic zone in Iran. In this study, the travertines were investigated applying petrography, mineralogy and isotope geochemistry. Oxygen and carbon isotope geochemistry, petrography, scanning electron microscopy (SEM) and X-ray powder diffraction (XRD) analysis were used to determine the source of the CO2 and the lithofacies and to classify the travertines. Isotope studies, morphological and mineralogical observations and distribution of travertines revealed that the travertines of the Qorveh-Takab could be of thermal water origin and, therefore, belong to the thermogene travertine category. These travertines are usually massive with mound-type morphology and are essentially found in regions with recent volcanic or high tectonic activity. The measured delta C-13 values of the travertines indicate that the delta C-13 of the CO2 released from the water during travertine deposition, while the source of the CO2 in the water springs seems to have been of crustal magmatic affinity. These travertines are divided into two lithofacies: (1) crystalline crust travertine and (2) pebbly (phytoclastic travertine with pebble-size extraclasts) travertine. delta O-18 and delta C-13 values of travertines are -0.6 to -11.9 (parts per thousand VPDB) and +6.08 to +9.84 (parts per thousand VPDB), respectively. A probable reason for the heavy carbon isotope content observed in these deposits is the presence of algae microorganisms, which was verified by SEM images. Fissure ridges, fluvial crusts with oncoids, and mound morphological features are observed in the study area. Based on the petrographic and SEM criteria, Qorveh-Takab travertines are classified into four groups: (1) compacted, (2) laminated, (3) iron-rich spring deposit and (4) aragonite-bearing travertines. Stable isotope compositions of Turkish travertines are largely similar to the travertines in the study area.

Oligocene successions in the North Alpine Foreland Basin (NAFB) and the Western Carpathians reflect Paratethys-wide paleogeographic changes, which also control their petroleum potential. Whereas these rocks have been studied in detail in both areas, the transition zone is still under-researched. In order to fill this gap, the Oligocene succession in the Waschberg Zone, comprising the Ottenthal Formation (NP21–23) and the overlying Thomasl Formation (NP23–24) has been studied using outcrop (Waldweg section) and borehole samples (Thomasl, Poysdorf) and a multidisciplinary approach. The Ottenthal Formation is subdivided from base to top into marls and shales (Ottenthal Mbr.), diatomaceous shales (Galgenberg Mbr.) and marlstones (Dynow Mbr.). Biogenic silica contents, determined using atomic absorption spectroscopy, reach 30 wt. % in the carbonate-free Galgenberg Member, but also in the Dynow Members, which is characterized by upward decreasing productivity of calcareous nannoplankton. Close lithological relations exist with the Oligocene succession in the NAFB, but diatoms are largely missing in the latter. Organic matter contents are surprisingly low in the Ottenthal and Thomasl formations in the Waldweg section, which therefore are poor hydrocarbon source rocks. In contrast, the Thomasl Formation, encountered in the Thomasl and Poysdorf boreholes, holds a fair to good hydrocarbon potential (~ 2.2–2.5 wt. % TOC; type III and type II kerogen) and may generate 1.0 to 1.6 tons of hydrocarbons/m2. Obviously TOC contents of borehole samples are significantly higher than in outcrop samples. Because of severe indications of weathering (e.g., presence of gypsum and jarosite), a detrimental effect of weathering on the samples from the Waldweg section cannot be excluded. Biomarker data suggest a nearshore depositional environment with changing oxygen-availability and salinity. Vitrinite reflectance measurements show that the investigated sections are thermally immature.

Abstract 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.

Abstract Oligocene and Lower Miocene deposits in the Paratethys are important source rocks, but reveal major stratigraphic and regional differences. As a consequence of the first Paratethys isolation, source rocks with very good oil potential accumulated during Early Oligocene time in the Central Paratethys. Coeval source rocks in the Eastern Paratethys are characterized by a lower source potential. With the exception of the Carpathian Basin and the eastern Kura Basin, the source potential of Upper Oligocene and Lower Miocene units is low. In general, this is also valid for rocks formed during the second (Kozakhurian) isolation of the Eastern Paratethys. However, upwelling along a shelf-break canyon caused deposition of prolific diatomaceous source rocks in the western Black Sea. Overall, Oligocene–Lower Miocene sediments in the Carpathian Basin (Menilite Formation) can generate up to 10 t HC m−2. Its high petroleum potential is a consequence of the interplay of very high productivity of siliceous organisms and excellent preservation in a deep silled basin. In contrast, the petroleum potential of Oligocene–Lower Miocene (Maikopian) sediments in the Eastern Paratethys is surprisingly low (often <2 t HC m−2). It is, therefore, questionable whether these sediments are the only source rocks in the Eastern Paratethys.

Two separate petroleum systems have been identified in the Austrian sector of the North Alpine Foreland Basin: a lower Oligocene – Cenomanian/Eocene oil and thermogenic gas system; and an Oligocene‐Miocene microbial gas system. Recent studies by both academic and industry‐based research groups have resulted in an improved understanding of these petroleum systems, which are reviewed in this paper.Lower Oligocene organic‐rich intervals (up to 12 %TOC; HI: 400–600 mgHC/gTOC), capable of generating slightly more than 1 t of hydrocarbons/m2, are the source rocks for the thermogenic petroleum system in the Austrian sector of the North Alpine Foreland Basin. The present‐day distribution of this source rock is controlled by submarine mass movements which removed a large part of the organic‐rich interval from its depositional location during the late early Oligocene. The transported material was redeposited in locations to the south which are at the present day buried beneath Alpine thrust sheets. In addition, source rock units were incorporated into Molasse imbricates during Alpine deformation. Hydrocarbon generation began during the Miocene, and the oil kitchen was located to the south of the Alpine thrust front. Hence, lateral migration over distances of up to 50 km was required to charge the mainly Eocene and Cenomanian non‐ and shallow‐marine sandstone reservoir units. Hydrocarbons are in general trapped in structures related to east‐west trending normal faults, and differences in source rock facies resulted in the development of separate western and eastern oil families. Surprisingly, with the exception of some fields in the eastern part of the study area, associated gas contains varying (and sometimes very high) percentages of primary and secondary microbial methane. The composition of oil in some fields is influenced by both biodegradation and water washing. Post‐Miocene uplift in the Austrian sector of the basin had further effects on biodegradation and the consequent formation of secondary microbial gas, and also resulted in re‐migration.The upper Oligocene to lower Miocene succession (Puchkirchen Group, Hall Formation) provides both source and reservoir rocks for the microbial petroleum system in the Austrian sector of the North Alpine Foreland Basin. TOC contents (<1.0 %) and HI values (<140 mgHC/gTOC) of pelitic source rocks are typically low. Microbial gas was generated shortly after deposition during early diagenesis and was subsequently fixed in gas hydrates. Basin subsidence and high sedimentation rates resulted in decomposition of the hydrates below their stability zone, and reservoirs were filled during the early Miocene. Subsequent mixing of microbial gas with thermogenic gas and condensates is widespread. However, biodegradation has prevented precise determination of the fraction of thermogenic hydrocarbons present in gas samples. Reservoir sandstones were deposited within a deep‐marine channel belt along the axis of the North Alpine Foreland Basin, and reservoir quality depends on the precise position within this belt. In the study area, gas is trapped in compaction anticlines or at channel margin pinch‐outs and additional traps are formed by imbrication structures.

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.

A strong relationship between carbonate precipitation and microbial gas generation is evident for the Upper Eocene reservoir rocks of the North Alpine Foreland Basin. To achieve a better understanding of this relationship, 40 samples of limnic to shallow marine, gas-, oil-and water-bearing sandstones were studied to determine mineralogy and diagenetic history. The specific mineral parageneses were used to reconstruct changes in the hydrogeochemical conditions over time. Thus, authigenic mineral phases within reservoir rocks are an important archive for the reconstruction of pore fluid composition changes.The eogenetic pore space evolution of investigated Eocene sandstones is influenced by their primary mineralogy, which is strongly controlled by (i) depositional environment, (ii) detrital input and (iii) transport distances. Thus, a low compositional maturity is associated with high feldspar and high clay mineral content. Authigenic clay minerals, formed during several stages of diagenesis, play an important role for reservoir quality, due to pore space reduction.During eogenesis, authigenic micritic and sparitic carbonate phases are precipitated, which decreases the pore space. These eogenetic carbonate cements exhibit isotope values of about delta C-13: -5.9 to + 2.2% and delta(18) O: -8.3 to -4.3% [VPDB]. Some of these sam delta(18) ples indicate a trend towards lighter delta(18) O values (-17.2%), which is attributed to meteoric flush.Within the Eocene sandstones, two types of strongly cemented zones with low permeabilities can be differentiated: (i) extraordinary light delta C-13 (-28.4%) carbonates, which formed due to degradation of organic matter at the stage of advanced sulfate reduction and (ii) heavy delta C-13 (delta C-13: + 8.7%), which precipitated at the fermentation zone.Within the reservoir sandstones telogenesis is characterized by mineral destabilization (e.g. carbonate and feldspar corrosion) and kaolinite precipitation. The formation of authigenic kaolinite booklets resulted into a decrease in porosity.

The most prolific oil shale deposit in Serbia is located in the Aleksinac Basin and is assigned to the Lower Miocene. Depositional environments and hydrocarbon potential were assessed for the Aleksinac oil shale and coal layers through bulk geochemical, organic petrographical, biomarker, and carbon isotope data from core samples from a single well. Maturity parameters (vitrinite reflectance, T-max, biomarker isomerisation ratios) prove that the organic matter (OM) is immature. A lower lacustrine oil shale sequence is comprised of alternating sandstone and clay-rich rocks and some thin coal beds, indicating strong variations in depositional environment. This stratum is covered with thick sandstone (50 m) terminated by the main 4 m thick coal seam that was deposited in a low-lying mire, as evidenced by high total sulfur and mineral matrix contents. The plant input was dominated by angiosperms. A relative rise in water level led to the drowning of the swamp and to the deposition of a 60 m thick upper oil shale in a lacustrine environment. The OM of the oil shale is dominated by kerogen Type I (lamalginite). Biomarker data suggest a stratified water column that likely formed due to differences in salinity. The stratified water column led to a strictly anoxic environment and photic zone euxinia in a mesosalinar, hydrologically closed lake, which enabled the accumulation of uncommonly high amounts of organic material (average TOC: 18.0 wt%) with excellent preservation (average HI: 743 mg HC/g TOC). (c) 2017 Elsevier Ltd. All rights reserved.

The type section of the Oligocene to lower Miocene Maikop Group, considered themain source rock in the eastern Paratethys, has been studied using geochemical proxies to gain insights into depositional setting and hydrocarbon potential. The Maikop Group at the type section is approximately 600 m (2000 ft) thick. Deposition commenced after a major late Eocene sea level drop and a subsequent early Oligocene sea level rise. The Maikop Group is composed mainly of carbonate-free pelitic rocks. Calcareous rocks are limited to the lower Oligocene succession, including the Polbian Bed that forms a basin-wide marker horizon deposited during a time with significantly decreased salinity (Solenovian event). Anoxic conditions prevailed and were only interrupted for longer periods during deposition of the lower part of the lower Oligocene Pshekha Formation, the Polbian Bed, and the lower Miocene Olginskaya Formation. Total organic carbon (TOC) contents range up to 3.5 wt. %. Hydrogen index values are typically less than 300 mg hydrocarbons (HC)/g TOC but reach 420 mg HC/g TOC in black shales overlying the Polbian Bed (lower Morozkina Balka Formation). Organic richness of this level, approximately 10 m (33 ft) thick, is controlled by low salinity and high bioproductivity. The Maikop Group could generate approximately 2.0 t HC/m(2) surface area. A significant part (0.45 t/m(2)) comes from the lower Morozkina Balka Formation, which generates a high-wax paraffinic-naphthenic- aromatic mixed oil. The Pshekha, upper Morozkina Balka, and Batalpashinsk Formations would generate low-wax oil or condensate. The hydrocarbon generation potential of the overlying formations is minor. Overall, the generation potential of the Maikop Group is surprisingly low.

The non-marine Santanghu Basin in northwest China hosts one of the richest and thickest Permian lacustrine source rock intervals in the world. Conventional oil in Jurassic sandstone reservoirs and tight oil in the tuffaceous Permian Tiaohu Formation were sourced from mudrocks in the underlying second member of Lucaogou Formation, which also have tight oil potential proved by recent commercial discoveries. Based on inorganic and organic geochemistry, organic petrography, and stable isotope geochemistry, the depositional environment and the tight oil potential of the second member of Permian Lucaogou Formation were investigated. The data imply a gradual evolution of the depositional environment from a stratified, saline to a freshwater lake. The succession can be subdivided into a lower, middle, and an upper unit, each characterized by decreasing water salinity. High bioproductivity has been caused by the bloom of algae and photosynthetic cyanobacteria. Water column stratification accelerated the activity of methanothrophs, as indicated by low δ13C values of hopanes. Biomarker composition provides evidence for decreasing contributions of cyanobacteria to the biomass and increasing abundance of Prasinophytae compared to other algae with decreasing salinity. Enhanced terrigenous organic matter input appeared during periods of high freshwater inflow. Low total organic carbon (TOC) contents in the lower unit are most likely caused by rapid sedimentation rate. High bioproductivity and excellent preservation conditions resulted in high TOC contents in the middle unit. Terrigenous organic matter input increased together with fresh water inflow in the upper unit, resulting in high TOC values during periods of possibly low sedimentation rates in a deep water column. The samples of the second member exhibit a good to very good potential to generate conventional oil. High TOC and extractable organic matter yields, together with the thickness of the fine-grained sediments, show that the middle and upper units of the second member of Lucaogou Formation hold significant tight oil potential. Mineralogical composition of this dolomite-rich shale with respect to abundance of brittle minerals (including quartz and carbonates) and rare clay testifies a good tight oil potential.

Molecular and stable isotope compositions were determined for forty eight gas samples taken from wells producing oil form Cretaceous and Eocene reservoirs. Gas was expelled from source rock at various maturity levels (0.6-1.2%Rr). Gas maturities based on stable carbon isotopes are in general agreement with those found in oils. Nevertheless, results revealed that most fields trap methane derived from a source which is not thermogenic. Shallow northeastern reservoirs trap methane interpreted as secondary microbial in origin. The same process is proposed here as source of methane in western deposits. Moreover, those gases are enriched in H-2 isotope suggesting different methanogenesis pathways. Fields along the southern margin of the Alpine Foreland Basin where reservoir temperature exceeds 80 degrees C host methane generated during primary organic matter degradation. Thus, Eocene and Lower Oligocene layers should be considered as potential source rocks. This study gives new insight to filling history of traps and revealed a more complicated geological background and hydrocarbons generation than have been assumed until now. (C) 2016 Elsevier Ltd. All rights reserved.