Jurassic Shales Research Articles

Basement-involved thin-skinned and thick-skinned tectonics in the Alps

AbstractThe deformation of continental crust during continental collision by folding and thrusting follows three types of structural styles: (1) in a true thin-skinned style only cover rocks are involved; (2) in the case of a thin-skinned basement-involved style, thin slabs of crystalline basement rocks are piled up into a nappe stack; (3) in a true thick-skinned style, the entire upper crust is involved in the deformation. In the Alps all three styles can be recognized. The Helvetic nappes and parts of the Penninic nappes exhibit true thin-skinned style tectonics. Triassic evaporites, Jurassic shales and Cretaceous marls acted as detachment horizons. Basement-involved thin-skinned tectonics is typical for the Penninic nappes in the core of the orogen. The thickness of the basement thrust sheets is controlled by the effects of Mesozoic rifting, by deep burial and heating of the subducting crust and by the presence of Late Palaeozoic structures. Thick-skinned style is observed in the more external parts of the orogen, the external massifs and the Southalpine nappe system. It occurred in the late phase of collision and involved the entire upper crust. The basal detachment occurred possibly along phyllonites generated by the breakdown of load-bearing feldspar. Considering the Alpine orogen as a whole, the lower crust deformed seemingly independently from the upper crust. The detachment of the cover units by thin-skinned tectonics occurred prior to thrusting related to basement-involved thin-skinned tectonics. Thrust faults of both types were overprinted by ‘post-nappe folding’.

Origin of organic matter and paleoenvironment conditions of the Late Jurassic organic-rich shales from shabwah sub-basin (western Yemen): Constraints from petrology and biological markers

Late Jurassic organic-rich shales from Shabwah sub-basin of western Yemen were analysed based on a combined investigations of organic geochemistry and petrology to define the origin, type of organic matter and the paleoenvironment conditions during deposition. The organic-rich shales have high total sulphur content values in the range of 1.49–4.92 wt. %, and excellent source rock potential is expected based on the high values of TOC (>7%), high extractable organic matter content and hydrocarbon yield exceeding 7000 ppm. The high total sulphur content and its relation with high organic carbon content indicate that the Late Jurassic organic-rich shales of the Shabwah sub-basin were deposited in a marine environment under suboxic-anoxic conditions. This has been evidenced from kerogen microscopy and their biomarker distributions. The kerogen microscopy investigation indicated that the Late Jurassic organic-rich shales contain an abundant liptinitic organic matter (i.e., alginite, structureless (amorphous organic matters)). The presence of alginite with morphology similar to the lamalginite alga and amorphous organic matter in these shale samples, further suggests a marine origin. The biomarker distributions also provide evidence for a major contribution by aquatic algae and microorganisms with a minor terrigenous organic matter input. The biomarkers are characterized by unimodal distribution of n-alkanes, low acyclic isoprenoids compared to normal alkanes, relatively high tricyclic terpanes compared to tetracyclic terpanes, and high proportion of C27 and C29 regular steranes compared to C28 regular sterane. Moreover, the suboxic to anoxic bottom water conditions as evidenced in these Late Jurassic shales is also supported based on relatively low pristane/phytane (Pr/Ph) ratios in the range of 0.80–1.14. Therefore, it is envisaged here that the high content of organic matter (TOC > 7 wt.%) in the analysed Late Jurassic shales is attributed to good organic matter (OM) preservation under suboxic to anoxic bottom water conditions during deposition.

Geological, geochemical, and fluid inclusion evidences for the origin of the Ravanj Pb–Ba–Ag deposit, north of Delijan city, Markazi Province, Iran

The Lower Cretaceous sequences of the Ravanj anticline in Iran host the Ravanj Pb-Ba-Ag mineralization. Economic orebodies are restricted to the thrust zone within the brecciated massive limestone and immediately above the Jurassic shale and/or shale-limestone intercalations of the Lower Cretaceous. Paragenetic sequence and distinct zoning of mineral assemblages indicate that ore-forming fluid migrated through thrust zones along the NE-trending faults. The REE pattern of mineralized host rock is characterized by HREE-enrichment ((La/Lu)PAAS = 0.24). The Ce/Ce* ratio of mineralized host samples shows negative Ce anomalies, which is most likely inherited from seawater. The positive Eu/Eu* anomaly suggests high ?O2 during ore deposition. Negative Δ34S values of the Ravanj sulfide minerals (-27? to -11?) suggest bacteriogenic sulfate reduction, whereas positive Δ34S values of barite (+20?) fall in the range of Tertiary marine sulfates. Multiple isotopic sulfur sources of sulfides and sulfate minerals support mixing of a reduced negative isotopic sulfur-bearing fluid and a positive isotopic sulfate-bearing fluid. The average of homogenization temperatures of fluid inclusions from the early and late-stage mineralization calcites are 165 and 160 °C, respectively. The salinity of fluid inclusions varies between 0.66 and 18 wt% NaCl equivalent with an outlier at 22.2. Wide variation in the salinity of fluid inclusions can be explained by fluid mixing between a higher salinity group with 14-18 wt% NaCl equivalent and a lower salinity group with 0.66-8 wt% NaCl equivalent. In the Ravanj, fine grained sulfide minerals are consistent with a sulfur supersaturated fluid. High concentrations of Pb can be present in oxidized, chlorine-bearing fluids if the concentration of total H2S is very low. Therefore, mixing of two geochemically different fluids could precipitate both galena and barite. These data show that the Ravanj Pb-Ba-Ag deposit is comparable with Pb-rich Mississippi Valley-type deposits such as the Viburnum Trend district in the USA.

Application of high-resolution 2D–3C seismic for characterization of the perspective Jurassic shale play in Central Poland

Here we show the application of broadband (4–120Hz) 2D–3C seismic for characterization of the perspective Jurassic shale play in Central Poland. Data were acquired along a network of 250km 2D profiles using single-point, densely spaced receivers (digital 3C sensors) and acquisition was focused on providing both high-resolution and broadband seismic that would enable structural imaging and quantitative interpretation of the key stratigraphic horizons in the Mesozoic sedimentary cover. Such acquisition parameters resulted in good quality data and allowed for more flexibility during processing, e.g., unaliased F–K filtering or digital group forming for ground-roll removal. Processing was oriented to preserve relative amplitudes and the broadband character of the dataset as the input for future quantitative interpretation. We obtained a high-resolution stratigraphic image of the target Upper Jurassic (Upper Kimmeridgian–Tithonian) sequence as well as overall structural portrait of this part of Mid-Polish Trough characterized by strong imprint of the salt tectonics. Lateral continuity of particular stratigraphic sequences has been determined and a more precise structural context for deposition and present-day structure of the Upper Kimmeridgian–Tithonian has been established.

Adsorption of methane, carbon dioxide and their binary mixtures on Jurassic shale from the Qaidam Basin in China

CO2-enhanced shale gas recovery, which plays a crucial role in energy resource development, involves the adsorption of binary mixtures of CH4 and CO2 on shale. While numerous previous studies have provided useful insight into CH4/CO2 sorption characteristics on shale, few studies have been conducted on binary mixtures absorption on shale. To get better understanding in this field, we carried out an experimental study using shale samples from the Qaidam Basin in China to investigate the adsorption mechanism of CH4 and CO2 and their binary mixtures on shales and to evaluate the shale CO2-enhanced gas recovery potential in more details. The results indicate that the CO2 sorption capacity exceeds that of the methane sorption by a factor of 4 for these shales. The study also shows that in the adsorption system of the mixtures, CO2 plays an advantageous role in the competitive adsorption process. The shale exhibits various behaviors of preferential adsorption of CO2, which can be related to the shale pore structure. Maximum values of isosteric heat of adsorption for CO2 and CH4 are found to be 17.7kJ/mol and 12.6kJ/mol respectively. In addition, our work denoted that the isosteric heat of adsorption for CO2 on shale samples increases with increasing adsorption capacity. The study suggests that the CO2-enhanced gas recovery pattern can be feasible for shales in the Qaidam Basin.

New Rock-Eval Method for Characterization of Unconventional Shale Resource Systems

Unconventional resources such as tight, fractured and hybrid shale gas and oil plays as well as oil or kerogen shale systems, are considered exploitable self-contained source and reservoir rocks. A better understanding of the thermal cracking of sedimentary organic matter, hydrocarbons generation, expulsion, storage and retention mechanisms constitutes a key point, estimating the oil and gas in-place, free or adsorbed, for their exploration and exploitation. Herein, we introduce a new ready to use method of analysis and interpretation for the Rock-Eval 6 device for better assessment of free or sorbed hydrocarbons in unconventional shale plays. This method was developed at IFP Energies nouvelles (France) and was tested on 15 actual or potential unconventional shale samples from Silurian Shale (Algeria), Mississippian Barnett Shale (USA), Early Jurassic Shale (France), Late Jurassic Bazhenov Shale (Russia) and Eocene Green River Shale at different thermal maturity stages. Results indicate a better quantification of free and/or sorbed hydrocarbons (Sh0 and Sh1 peaks) as well as a more accurate determination of the Rock-Eval T max maturity parameter.

Analysis of geological effects on methane adsorption capacity of continental shale: a case study of the Jurassic shale in the Tarim Basin, northwestern China

AbstractThe Jurassic shale is an important source rock for the found gas reservoirs in the Tarim Basin, northwestern China, but has never been researched for shale gas potential. The geological effects on methane adsorption capacity for the gas shale have been investigated in this paper through the geochemical, mineralogical and adsorption analyses on samples from wells and sections. The methane adsorption capacity ranges from 0.58 to 16.57 cm3/g, and the total organic carbon (TOC) content is between 0.5 and 13.5 wt%. The organic maturity measured by Tmax is between 410 °C (immature) and 499 °C (overmature). The methane adsorption capacity of the Jurassic continental shale in the Tarim Basin is affected by many geological factors, including the TOC content, organic matter maturity, mineral composition, surface area and pore size distribution. The TOC content is the most significant factor with a positive effect on the adsorption capacity of the Jurassic shale, and the influence varies piecewise according to the TOC content. The TOC content contributes much more to the methane adsorption capacity of organic‐rich shale samples (TOC content > 0.7 wt%) than to the organic‐lean samples (TOC content < 0.7 wt%). The mineral composition is a secondary factor, and the abundance of clay content has a positive effect on the methane adsorption capacity despite its relatively weaker adsorption ability compared to TOC. The pore size distribution has different effects on surface area and pore volume. Mesopores and micropores provide the major surface area and are mainly derived from TOC and illite, which has a positive influence on the adsorption capacity. Mesopores and macropores offer the major pore volume and are mainly formed by illite, which is the major contributor for pore volume rather than surface area. In addition, the TOC and illite contents of the Jurassic shale in the Tarim Basin are closely related to the origin, maturity and diagenesis evolution of the shale: (1) both TOC and illite content variations are related to the different provenances and depositional environments of shale; (2) the decrease of TOC content with increasing maturity is also partly attributed to hydrocarbon generation; and (3) the increase of illite content with increasing maturity is due to illitization in the diagenesis of shale. Copyright © 2015 John Wiley & Sons, Ltd.

Inherited tectonic structures controlling the deformation style: an example from the Helvetic nappes of the Eastern Alps

Based upon tectonic as well as facies arguments, two different Helvetic nappes can be distinguished in western Austria (Vorarlberg) and in southwestern Germany (Upper Allgau): the Hohenems nappe and the overlying Vorarlberg Santis nappe. Both encompass Middle Jurassic to Eocene strata deposited on the internal to external shelf of the southward deepening European margin of the Eurasian plate. Synsedimentary normal faults caused changes in thickness and facies of the various strata, which play a crucial role in deformation behavior. Arcuate fold axes in map view and an almost 3 km thick sequence of stacked Middle Jurassic shales and sandstones drilled below a Jurassic anticlinorium in the southern part of the Bregenzerwald are thought to be indicative of an inverted Jurassic basin. Inversion occurred during the Cenozoic Alpine nappe formation along synsedimentary normal faults, reactivated as ramps and tear faults. A lateral ramp, segmented by tear faults, running along the Iller Valley, and a supposed lateral ramp in the subsurface of the Rhine Valley mark the extension of the inverted former basin. Fault deformation style changes across the Rhine Valley. East of it, i.e. in Vorarlberg, the Vorarlberg Santis nappe comprises a coherent succession of Jurassic and Cretaceous strata detached along Middle Jurassic sediments. In the west, on the other hand, Cretaceous strata of the Swiss Santis nappe were largely detached from their Jurassic substrate (Gonzen-Walenstadt imbricates) along the Santis thrust. This allows to correlate the Helvetic nappe stack of eastern Switzerland, comprising the Swiss Santis nappe (together with the Gonzen-Walenstadt imbricates) and the underlying Murtschen nappe, with the Vorarlberg Santis nappe and the Hohenems nappe of Austria.

Permeability, compressibility and porosity of Jurassic shale from the Norwegian–Danish Basin

The Fjerritslev Formation in the Norwegian–Danish Basin forms the main seal to Upper Triassic–Lower Jurassic sandstone reservoirs. In order to estimate the sealing potential and rock properties, samples from the deep wells Vedsted-1 in Jylland, and Stenlille-2 and Stenlille-5 on Sjælland, were studied and compared to samples from Skjold Flank-1in the Central North Sea. Mineralogical analyses based on X-ray diffractometry (XRD) show that onshore shales from the Norwegian–Danish Basin are siltier than offshore shales from the Central Graben. Illite and kaolinite dominate the clay fraction. Porosity measurements obtained using helium porosimetry–mercury immersion (HPMI), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) techniques on the shale samples show that MICP porosity is 6–10% lower than HPMI or NMR porosity. Compressibility, from uniaxial loading, and elastic wave velocities were measured simultaneously on saturated samples under drained conditions at room temperature. Uniaxial loading tests indicate that shale is significantly stiffer in situ than is normally assumed in geotechnical modelling. Permeability can be predicted from elastic moduli, and from combined MICP and NMR data. The permeability predicted from Brunauer–Emmett–Teller (BET)-specific surface-area measurements using Kozeny’s formulation for these shales, being rich in silt and kaolinite, falls in the same order of magnitude as permeability measured from constant rate of strain (CRS) experiments but is two–three orders of magnitude higher than the permeability predicted from the 1998 model of Yang & Aplin, which is based on clay fraction and average pore radius. When interpreting CRS data, Biot’s coefficient has a significant and systematic influence on the resulting permeability of deeply buried shale.

Identification of homoglycerol- and dihomoglycerol-containing isoprenoid tetraether lipid cores in aquatic sediments and a soil

Lipid extracts from several aquatic sediments and a compost-fertilised soil contained higher homologues of widely reported archaeal diglycerol tetraether cores. Liquid chromatography–tandem mass spectrometry indicated that the structures are based on polyols not reported in archaeal membrane lipids, homoglycerol (GH; C4H8O3) or dihomoglycerol (GDH; C5H10O3) groups, which replace one of the terminal glycerol (C3H6O3) moieties in the diglycerol lipids. The homologues include monoalkyl, dialkyl and trialkyl tetraether cores, some of which were inferred to contain cyclopentyl rings. Distributional differences between diglycerol tetraethers and associated homologues in all the samples indicate a biogenic route and not a diagenetic route to the latter. The homologues are prominent components of tetraether distributions in some samples (up to ca. 22% of isoprenoid tetraether lipid cores), are preserved in ancient sediments (e.g. Jurassic shales, 160Ma) and occur in disparate terrestrial and oceanic settings. Hence, their presence in other sedimentary archives can be expected. The components clearly encode different information from that encoded in the diglycerol tetraethers and may allow refinement of interpretations from environmental ether lipid distributions.

Diagenetic Process and Pore Evolution of Jurassic Continental Shale in Tarim Basin, Northwest China

The Jurassic shale in the Tarim Basin, as one of the important source rocks within the basin, is identified as a set of typical continental sedimentation with big hydrocarbon-generating potential. The diagenetic process and pore evolution characteristics of the Jurassic shale were studied based on geochemical and reservoir bed properties analyses and scanning electron microscope (SEM) observation. The results show that the Jurassic shale shows low-porosity and low-permeability, the mineral composition is mainly of clay mineral and quartz; the shale underwent three diagenetic evolutionary stages, namely syngenetic to Period A of early diagenetic stage, Period B of early diagenetic stage and Period A of middle diagenetic stage; during this process, the shale underwent a series of changes such as hydrocarbon generation of organic matter, conversion from original minerals to illite, formation of authigenic minerals, recrystallization and corrosion; meanwhile, porosity and permeability also underwent the evolutionary processes including rapid reduce of primary pore and development of secondary pore. The pore development within shale is mainly controlled from three aspects, namely material composition of rock, diagenesis and later tectonic reworking.

Equivalent pore radius and velocity of elastic waves in shale. Skjold Flank-1 Well, Danish North Sea

Abstract Equivalent pore radius links permeability and porosity of a porous medium. This property can be calculated from specific surface and porosity data measured in the laboratory. We can obtain porosity information from logging data but specific surface information can only be obtained from laboratory experiments on cuttings or core samples. In this study we demonstrate that elastic moduli as calculated from bulk density and velocity of elastic waves relate to equivalent pore radius of the studied shale intervals. This relationship establishes the possibility of calculating equivalent pore radius from logging data. We used cuttings samples and available well logs to characterize Cenozoic, Cretaceous and Jurassic shale sections in the Skjold Flank-1 well of Danish North Sea. Logging data and well reports were used to select 31 shale cuttings samples and experimental data for porosity, grain density and BET specific surface were obtained from these samples using kaolinite and smectite as reference. The cuttings samples were also characterized with respect to mineralogical composition, content of organic carbon and cation exchange capacity. Equivalent pore radius was calculated from porosity and BET data. It varies from 5 nm for some Cretacous and Jurassic shale samples to about 25 nm in some Cenozoic samples. Pore radius is controlled by shale mineralogy and the degree of compaction. We found exponential relationships between equivalent pore radius and elastic moduli, and these empirical relationships were used to calculate equivalent pore radius for the Cenozoic, Cretaceous and Jurassic shale sections in Skjold Flank-1 well from elastic moduli. Elastic moduli were calculated from sonic velocity and density logs. The calculated equivalent pore radius logs vary from 27 nm at 500 m to 13 nm at 2000 m within Cenozoic shale and from 12 nm to about 6 nm in the deeper Cretaceous and Jurassic shale intervals. Cross plots of the equivalent pore radius with neutron porosity and gamma ray data separate the Cenozoic shale section with high equivalent pore radius from Cretaceous and Jurassic sections.

Analysis of structural trends of sub-sea-floor strata in the Isfjorden area of the West Spitsbergen Fold-and-Thrust Belt based on multichannel seismic data

A dense grid of 2D multichannel seismic data was used for the interpretation of sub-sea-floor structures in the area of Isfjorden in western Spitsbergen. West Spitsbergen underwent Eocene transpressional deformation that resulted in formation of the West Spitsbergen Fold-and-Thrust Belt. Three horizons were defined for the seismic interpretation as well-expressed and continuous reflections: (1) the top of the metamorphic basement; (2) the base of the upper Carboniferous Nordenskiöldbreen Formation; (3) the base of the Lower Cretaceous Helvetiafjellet Formation. Time–structure maps and analysis of the sub-bottom structural trends were generated for each horizon. The top of the metamorphic basement displays north–south-trending graben structures, apparently representing continuation of the Devonian grabens from northern Spitsbergen. The tectonostratigraphic unit bounded by the base of the upper Carboniferous Nordenskiöldbreen Formation and base of the Helvetiafjellet Formation encloses the fold-and-thrust belt and is affiliated with WSW–ENE shortening involving three décollement levels. Within this unit the strata between the middle (Triassic shales) and upper (Upper Jurassic shales) décollements have undergone the most intense strain, whereas sediments situated between the basal (lower Permian evaporites) and middle décollements underwent a relatively mild deformation. The strata above the base of the Helvetiafjellet Formation are characterized by minor Tertiary deformation only.

Cenozoic reactivation of the Great Glen Fault, Scotland: additional evidence and possible causes

The Great Glen Fault trends NNE–SSW across northern Scotland. According to previous studies, the Great Glen Fault developed as a left-lateral strike-slip fault during the Caledonian Orogeny (Ordovician to Early Devonian). However, it then reactivated right-laterally in the Tertiary. We discuss additional evidence for this later phase. At Eathie and Shandwick, minor folds and faults in fossiliferous Jurassic marine strata indicate post-depositional right-lateral slip. In Jurassic shale, we have found bedding-parallel calcite veins (‘beef’ and ‘cone-in-cone’) that may provide evidence for overpressure development and maturation of organic matter at significant depth. Thus, the Jurassic strata at Eathie and Shandwick accumulated deeper offshore in the Moray Firth and were subject to Cenozoic exhumation during right-lateral displacement along the Great Glen Fault, as suggested by previous researchers. Differential sea-floor spreading along the NE Atlantic ridge system generated left-lateral transpressional displacements along the Faroe Fracture Zone from the Early Eocene to the Late Oligocene ( c . 47–26 Ma), a period of uplift and exhumation in Scotland. We suggest that such differential spreading was responsible for reactivation of the Great Glen Fault. Indeed, left-lateral slip along the Faroe Fracture Zone is compatible with right-lateral reactivation of the Great Glen Fault.

The source rock potential of the Upper Jurassic– lowermost Cretaceous in the Danish and southern Norwegian sectors of the Central Graben, North Sea

The principal source rocks in the Danish and southern Norwegian Central Graben in the North Sea are the Upper Jurassic to lowermost Cretaceous marine shales of the Mandal and Farsund formations. The distribution of generation potential and thermal maturity is quite complex. Biomarkers of crude oils from the northern Danish Central Graben indicate correlation to the Bo Member of the upper Farsund Formation or to the lower part of the formation. Biomarker ratios of oils from the Danish Chalk reservoirs show a maturity gradation from south to north, with oils in the northern part being more mature. Vitrinite reflectance gradients show differences in depth of the ‘top oil window’. In areas characterized by HPHT conditions and thick overlying Chalk, petroleum generation is retarded and the oil window is displaced downwards by 200–350 m. Source rock quality varies. The upper part of the shales is generally considered the most oil-prone. However, analyses indicate that the lower part of the Farsund Formation may contain intervals with rich oil-prone shales. Furthermore, the petroleum generation of the Upper Jurassic shales below the Farsund Formation is often overlooked, but source rock data indicate that gas/oil-prone, and to some extent oil-prone, shales are present.

Major and trace element compositions (including REE) of mineral, thermal, mine and surface waters in SW Germany and implications for water–rock interaction

The near-surface water cycle in a geologically complex area comprises very different sources including meteoric, metamorphic and magmatic ones. Fluids from these sources can react with sedimentary, magmatic and/or metamorphic rocks at various depths. The current study reports a large number of major, minor and trace element analyses of meteoric, mineral, thermal and mine waters from a geologically well-known and variable area of about 200×150km in SW Germany. The geology of this area comprises a Variscan granitic and gneissic basement overlain in parts by Triassic and Jurassic shales, sandstones and limestones. In both the basement and the sedimentary rocks, hydrothermal mineralization occurs (including Pb, Cu, As, Zn, U, Co and many others) which were mined in former times. Mineral waters, thermal waters and meteoric waters flowing through abandoned mines (mine waters) are distributed throughout the area, although the mine waters concentrate in and around the Schwarzwald.The present analyses show, that the major element composition of a particular water is determined by the type of surrounding rock (e.g., crystalline or sedimentary rocks) and the depth from which the water originates. For waters from crystalline rocks it is the origin of the water that determines whether the sample is Na–Cl dominant (deeper origin) or Ca–HCO3 dominant (shallow origin). In contrast, compositions of waters from sedimentary rocks are determined by the availability of easily soluble minerals like calcite (Ca–HCO3 dominant), halite (Na–Cl dominant) or gypsum (Ca–SO4 dominant). Major element data alone cannot, therefore, be used to trace the origin of a water. However, the combination of major element composition with trace element data can provide further information with respect to flow paths and fluid–rock interaction processes. Accordingly, trace element analyses showed, that:−Ce anomalies can be used as an indicator for the origin of a water. Whereas surface waters have negative or strongly negative Ce anomalies, waters originating from greater depths show no or only weak negative Ce anomalies.−Eu anomalies can be used to differentiate between host rocks. Waters from gneisses display positive Eu anomalies, whereas waters from granites have negative ones. Waters from sedimentary rocks do not display any Eu anomalies.−Rb and Cs can also be indicators for the rock with which the fluid interacted: Rb and Cs correlate positively in most waters with Rb/Cs ratios of ∼2, which suggests that these waters are in equilibrium with the clay minerals in the rocks. Rb/Cs ratios >5 indicate reaction of a water with existing clay minerals, whereas Rb/Cs ratios <2 are probably related to host rock alteration and clay mineral formation.The chemical compositions of carbonate precipitates from thermal waters indicate that rare earth elements (REEs), Rb and Cs concentrations in the minerals are controlled by the incorporation of clay particles that adsorb these elements.

Evaluating Seal Quality for Potential Storage Sites in the Norwegian North Sea

Caprock quality is crucial when wanting to evaluate the storage potential of a reservoir. The objective of this study is to evaluate the quality of the primary and secondary seal in case of CO2 storage in sandstones form the Mid to Late Jurassic in the Norwegian North Sea. These seals are composed respectively of Lower Cretaceous and Upper Jurassic shales for the primary, and from the three Cenozoic groups (Nordland, Hordaland and Rogaland) for the secondary.The primary seal is in general of sufficient thickness according to the recommendations from the Norwegian Petroleum Directorate (over 50 meters), except in a thin North-South corridor to the West of the platform, in the inner part of the grabens. This seal is brittle in the entire study area due to a deep burial depth. The only area where it could be ductile is to the North of the Utsira High, which is due to a warmer geothermal gradient but also possibly the movement of a basement fault beneath. Since its rheology is brittle, the primary seal could be breached during fault movements. To ensure its efficiency, it is thus important to evaluate the properties of the faults from this area that have a direction less than 30° away from the regional maximum horizontal stress (ENE-WSW)The secondary seal is much shallower and therefore has a ductile rheology which makes it less affected by fault movements. This is due to the nature of ductile deformation which creates less conductive faults that have self- healing properties. The thickness is also at least 500 meters close to the shore, but most commonly between 1000 and 2000 meters. These properties make it a high quality secondary seal, as has been demonstrated by the successful Sleipner storage site in the Utsira sands that are sealed by Nordland shales.

Fracture evolution in oil-producing sills of the Rio Grande Valley, northern Neuquén Basin, Argentina

Oil-producing sills are commonly considered atypical reservoirs, although they can hold significant exploration potential. The need for a better understanding of fracture properties and petroleum system characteristics for this and similar igneous rock plays is the main motivation of our study. We explore the evolution of this play type by an analysis of the Los Cavaos oil field, located in the Malargue fold belt of the Neuquen Basin, Argentina, integrating multiscale fracture data from outcrops and subsurface. The field was created by a combination of intrusions and mild Miocene-Pliocene inversion. Production stems from thick cavity zones in naturally fractured andesitic sills emplaced in Upper Jurassic shale source rocks. Orientation patterns, fracture spacing, and length of fracture sets in the sill are consistent over several orders of magnitude. Large multiply connected and weakly cemented fractures are responsible for excellent interconnectedness in the reservoir. Fracture density is correlated with fault proximity, indicating a cogenetic evolution during active deformation. Abundant fractures in core with strike-slip to oblique striations support transpressional overprint during and after fracture formation. Although it is challenging to separate cooling from tectonic fractures, we propose two phases of fracturing, marked by a coexistence of subvertical and oblique fractures together with transpressional striae. Petrographic evidence suggests initial local oil expulsion and migration through microfractures, with opening displacements of 0.01 to 1 mm, followed by subsequent charging of the evolving intrasill cavity system as well as the bulk fracture system during cooling and mild deformation. We suggest that the observed patterns may be extrapolated to sills in similar geotectonic settings.

Oil families and their inferred source rocks in the Barents Sea and northern Timan-Pechora Basin, Russia

A geochemical study of 34 oil samples was conducted to understand the types and distributions of effective source rocks and evaluate the geographic extent of the petroleum systems in the Barents Sea and northern Timan-Pechora Basin. Taxon-specific, age-related, and source-related biological markers (biomarkers) and isotope data provided information on the depositional environment of the source rock, source input, and source age of the oil samples. A relationship between biomarker and diamondoid concentration was used to identify mixed oils having both oil window and highly cracked components. Compound-specific isotope analyses of diamondoids and n-alkanes were used to deconvolute cosourced oils and identify deep source rocks in the basin. Results suggest five major source rocks in the Barents Sea and the northern Timan-Pechora Basin: Upper Jurassic shale, Lower–Middle Jurassic shale, Triassic carbonate and shale, Devonian marl, and Devonian carbonate. The Upper and Lower–Middle Jurassic source rocks are dominant in the Barents Sea. Triassic source rock consists of carbonate in the onshore part of northern Timan-Pechora Basin and marine shale in the Barents Sea. The Devonian Domanik Formation carbonate source rock extends offshore into the southern Barents Sea. The high-maturity Domanik Formation could also be a secondary source rock for most of the mixed oils in the northern Timan-Pechora Basin. This detailed geochemical study provides a new and detailed understanding of petroleum systems in the Barents Sea and northern Timan-Pechora Basin.

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

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