Dissolved noble gases and stable isotopes as tracers of preferential fluid flow along faults in the Lower Rhine Embayment, Germany

Groundwater in shallow unconsolidated sedimentary aquifers close to the Bornheim fault in the Lower Rhine Embayment (LRE), Germany, has relatively low δ2H and δ18O values in comparison to regional modern groundwater recharge, and 4He concentrations up to 1.7 × 10−4 cm3 (STP) g–1 ± 2.2 % which is approximately four orders of magnitude higher than expected due to solubility equilibrium with the atmosphere. Groundwater age dating based on estimated in situ production and terrigenic flux of helium provides a groundwater residence time of ∼107 years. Although fluid exchange between the deep basal aquifer system and the upper aquifer layers is generally impeded by confining clay layers and lignite, this study’s geochemical data suggest, for the first time, that deep circulating fluids penetrate shallow aquifers in the locality of fault zones, implying  that sub-vertical fluid flow occurs along faults in the LRE. However, large hydraulic-head gradients observed across many faults suggest that they act as barriers to lateral groundwater flow. Therefore, the geochemical data reported here also substantiate a conduit-barrier model of fault-zone hydrogeology in unconsolidated sedimentary deposits, as well as corroborating the concept that faults in unconsolidated aquifer systems can act as loci for hydraulic connectivity between deep and shallow aquifers. The implications of fluid flow along faults in sedimentary basins worldwide are far reaching and of particular concern for carbon capture and storage (CCS) programmes, impacts of deep shale gas recovery for shallow groundwater aquifers, and nuclear waste storage sites where fault zones could act as potential leakage pathways for hazardous fluids

Reservoir stress path and induced seismic anisotropy: Results from linking coupled fluid-flow/geomechanical simulation with seismic modelling

We present a workflow linking coupled fluid-flow and geomechanical simulation with seismic modelling to predict seismic anisotropy induced by nonhydrostatic stress changes. We generate seismic models from coupled simulations to examine the relationship between reservoir geometry, stress path and seismic anisotropy. The results indicate that geometry influences the evolution of stress, which leads to stress-induced seismic anisotropy. Although stress anisotropy is high for the small reservoir, the effect of stress arching and the ability of the side-burden to support the excess load limit the overall change in effective stress and hence seismic anisotropy. For the extensive reservoir, stress anisotropy and induced seismic anisotropy are high. The extensive and elongate reservoirs experience significant compaction, where the inefficiency of the developed stress arching in the side-burden cannot support the excess load. The elongate reservoir displays significant stress asymmetry, with seismic anisotropy developing predominantly along the long-edge of the reservoir. We show that the link between stress path parameters and seismic anisotropy is complex, where the anisotropic symmetry is controlled not only by model geometry but also the nonlinear rock physics model used. Nevertheless, a workflow has been developed to model seismic anisotropy induced by non-hydrostatic stress changes, allowing field observations of anisotropy to be linked with geomechanical models

Measurement of the tt̄W and tt̄Z production cross sections in pp collisions at √s = 8 TeV with the ATLAS detector

The production cross sections of top-quark pairs in association with massive vector bosons have been measured using data from pp collisions at s√ = 8 TeV. The dataset corresponds to an integrated luminosity of 20.3 fb−¹ collected by the ATLAS detector in 2012 at the LHC. Final states with two, three or four leptons are considered. A fit to the data considering the tt̄W and tt̄Z processes simultaneously yields a significance of 5.0σ (4.2σ) over the background-only hypothesis for tt¯Wtt¯W (tt̄Z) production. The measured cross sections are σtt̄W = 369 + 100−91 fb and σtt̄Z = 176 + 58−52 fb. The background-only hypothesis with neither tt̄W nor tt̄Z production is excluded at 7.1σ. All measurements are consistent with next-to-leading-order calculations for the tt̄W and tt̄Z processes

Linking preferred orientations to elastic anisotropy in muderong shale, Australia

The significance of shales for unconventional hydrocarbon reservoirs, nuclear waste repositories, and geologic carbon stor- age has opened new research frontiers in geophysics. Among many of its unique physical properties, elastic anisotropy had long been investigated by experimental and computational ap- proaches. Here, we calculated elastic properties of Cretaceous Muderong Shale from Australia with a self-consistent averaging method based on microstructural information. The volume frac- tion and crystallographic preferred orientation distributions of constituent minerals were based on synchrotron x-ray diffrac- tion experiments. Aspect ratios of minerals and pores, deter- mined from scanning electron microscopy, were introduced in the self-consistent averaging. Our analysis suggested that phyllosilicates (i.e., illite-mica, illite-smectite, kaolinite, and chlorite) were dominant with ~70 vol:%. The shape of clay platelets displayed an average aspect ratio of 0.05. These plate- lets were aligned parallel to the bedding plane with a high degree of preferred orientation. The estimated porosity at am- bient pressure was ~17 vol:% and was divided into equiaxial pores and flat pores with an average aspect ratio of 0.01. Our model gave results that compared satisfactorily with values derived from ultrasonic velocity measurements, confirming the validity and reliability of our approximations and averaging approach

Influence of organic matter type on porosity development in the Wufeng-Longmaxi Shale: A combined microscopy, neutron scattering and physisorption approach

The upper Ordovician Wufeng Shale and lower Silurian Longmaxi Shale are part of the Fuling shale gas play located in the south-eastern part of the Sichuan Basin, southern China, representing the first commercial shale gas production project outside North America. We studied the occurrence of porosity at the micro- and nano-scale in samples of contrasting organic richness representing the typical lithofacies from the post-mature part of the Wufeng-Longmaxi gas play. Using a combination of site specific, high-resolution scanning and transmission electron microscopy with bulk measurements based on small angle neutron scattering and cryogenic Argon physisorption, along with conventional organic petrology, we highlight the impact of different types of organic matter (OM) (primary versus secondary) on the development of OM-hosted porosity. The results indicate that at the bulk scale the overall porosity in the samples is proportional to their organic content and organic hosted pore account for 30–40% of the total pore volume of the rocks. Nevertheless, most of the pores identified via electron microscopy imaging seem to reside in the organic matter, indicating that potentially a large part of the pores volume detected by neutron scattering and Argon physisorption is visually not detected. Organic matter focused nanoscale imaging revealed that mesopores are preferentially present in the solid bitumen and not in the primary detrital organic particles. Organic lean samples show low porosity and dominance of micropores, while organic-rich samples show higher porosity and a broader spectrum of pore sizes. Importantly, most of the meso pores are located in organic matter petrographically interpreted as solid bitumen, while detrital organic particles like graptolites show minimal visible porosity under high resolution electron microscopy and pore sizes in the micro pore range (i.e. <2 nm). Distinguishing between primary and secondary OM is therefore important for understanding the creation of an interconnected network of porous OM during hydrocarbon migration. This may have an important control on the estimation of gas in place and the gas transport properties of the shale