Raphael A. J. Wust

The anion-accessible porosity fraction (fa) is an important parameter controlling solute transport in claystones. A safe disposal of nuclear waste in such rocks relies on a comprehensive understanding of transport in clays. In stratigraphic sequences, established Cl or Br profiles provide insights into the paleo-hydrogeological evolution. Anion concentrations in the accessible porewater can be calculated from measured bulk porewater concentrations and the anion-accessible porosity fraction fa. Since experimental data for fa are scarce, and data extrapolation within a heterogeneous stratigraphy is challenging due to the fa dependency on multiple parameters (e.g., pore/grain shapes and size distributions), detailed understanding of texture and its influence on macroscopic transport parameters is paramount.In this study, imaging techniques (µCT and SEM) and other methods (e.g., N2 adsorption) were combined to characterise texture and the pore network of rock samples from Opalinus Clay and confining units. The techniques unravel pore characteristics at different scales: N2 adsorption from nanometers to a micrometer, SEM larger than 50 nm, and µCT larger than a few µm. Samples with different mineralogical compositions, lithologies, and experimentally determined fa for Cl (fCl) were analysed.Two sand/siltstone samples with different fCl but similar clay content show identical ratios of grains to porous clay regions, but different pore sizes in high-resolution SEM images. This can qualitatively explain the different fCl for these samples. However, SEM cannot resolve small pores (

Passive safety is a fundamental principle of any deep geological disposal for radioactive waste, aimed at protecting humans and the environment until the activity of the radioactive waste decays to levels comparable to those of natural rocks. In Switzerland, Nagra submitted a general licence application in November 2024 for a deep geological repository to be constructed in the Opalinus Clay host rock in the Nördlich Lägern siting region. The general licence application is the conclusion of Switzerland’s multi-stage site selection process to determine the most effective and ideal site for the long-term isolation of the radioactive waste. The Nördlich Lägern region lacks significant natural resources (hydrocarbons, salt, water, minerals, etc.) at or below the level of the repository. This limits motivation for future human intrusion related to the exploration of resources, thereby reducing future human actions that could compromise repository safety. The repository design incorporates a multi-barrier system that includes high-level waste disposal canisters that safely enclose the waste for thousands of years, well beyond the thermal phase. In combination with the significant repository depth, foreseeable inadvertent human intrusion is unlikely and difficult. Due to the depth of the repository (for both high-level waste and low- and intermediate-level waste), drilling is the only foreseeable future human action via which recovered waste material could reach the biosphere, potentially impacting health. Additionally, the disposal canisters for high-level waste present very small targets, reducing the likelihood of being hit by wildcat drilling activities. This paper explores 1) design, strategies and measures implemented to ensure post-closure safety of the repository, and 2) potential radiological consequences of an unlikely penetration of waste by drilling. To assess an unlikely event of future human action leading to the intrusion into the radioactive waste in Nördlich Lägern, stylised scenarios were developed using features, event, and processes. The intrusion scenarios focus on borehole scenarios. Consequences for the drilling team are excluded due to the regulatory framework. The borehole scenarios consider pessimistic parameter assumptions to assess the potential radiological consequences for the biosphere in the region between 100 and 50,000 years post closure. In the short term, key dose-relevant radionuclides include Sr-90, Am-241, Cs-137, Ni-63, Pu-239, and Ag-108. Over longer time scales, Cl-36, I-129, Pu-240, Nb-94, Th-230, Ra-226, and U-234 become more relevant. All scenarios result in dose consequences below the regulatory limit prescribed and include an unrealistic exfiltration pathway for radionuclides which is implausible in the context of the clay-rich sedimentary environment. Overall, the Swiss siting region represents an ideal site for the long-term disposal of radioactive waste due to its high level of passive safety and lack of potential resources. Only worst-case conservatisms and assumptions allow us to identify consequences for the regional biosphere for drilling events and even under such conditions, dose consequences remain well below the regulatory limits for future human actions, supporting the safety case and the long-term isolation of waste from the biosphere.

The Devonian Duvernay Formation in Alberta is a carbonate-siliceous unconventional source rock that produces prolific oil, gas condensate liquids, and gas. In the southern part of the basin and the East Shale Basin, high frequency interbeds of limestone and organic-rich calcareous shales are common at spacing of inches to several feet. Prolific gas liquids are trapped within the shale/mudstone units while the highly cemented and tight carbonate units show a lack of hydrocarbons. Even though most wellbores completed to date have primarily landed in shale units, still, due to geo-steering and other considerations penetration through limestone unit along the lateral cannot be avoided. High contrast in mechanical properties of shale and limestone units along with anisotropy in geomechanical properties of the same rock unit makes optimal hydraulic fracturing breakthrough and placement often challenging. This study reviews examples of high resolution mechanical Duvernay stratigraphy combined with log and core analyses in order to better understand the implications of hydraulic fracture development through such complex reservoirs. Integrated petrophysical well log and core data indicate that there are strong heterogeneities on lithology, and geomechanical properties (hardness, brittleness, and elastic properties) on various scales. The shale units generally have lower Young's modulus and Poisson's ratio, whereas the carbonate units have high Young's modulus and Poisson's ratio. Core data also indicate strong vertical transverse isotropy in the shale units. Combined with occurrence of various types of naturally-occurred sub-vertical fractures and sub-horizontal polished slip faces, weak bedding plane strength, and strong anisotropy in in-situ stresses, and high heterogeneities in lithology and geomechanical properties likely result in complex and poorly constrained and un-optimized hydraulic fractures throughout the Duvernay Formation. The results indicate that high Young's modulus of carbonates causes a narrow fracture width which makes fracture initiation and placement and in particular proppant transport a challenge. Normal and strike slip faulting regimes are observed in some areas of East Basin. The lower anisotropy in horizontal stresses estimated for the shale zones than the carbonate zone may suggest that the complex fractures is more likely to occur in the shale zones than the carbonate zones. In Duvernay minifrac tests, longer fall off data collection (> 2 weeks) is critical for a successful determination of closure pressure and pore pressure estimation. During fracture stimulations, tight cluster spacing, i.e. ≤10m apart, might limit fracture geometry growth on the inner clusters due to higher induced stress. Similarly, due to higher stress shadow effects, tighter stage spacing might affect the fracture growth on the subsequent stages.

For optimizing and enhancing hydrocarbon recovery from unconventional plays, the technological race is currently focused on development and production of state-of-the-art surfactants that reduce interfacial tension to mitigate obstructive capillary forces and thus increase the relative permeability to hydrocarbon (k_ro). This study provides insight into the pore-scale evaluation of the latest flowback enhancer technologies currently applied in the Permian Basin, Texas, USA. A multidisciplinary approach, including concepts of nanotechnology, was used to assess fluid-fluid and rock-fluid interactions occurring at the nanopore scale and their implications on enhancing oil recovery. A heterogeneous dual-porosity dual-permeability microfluidic chip was designed and developed with pore geometries representing shale formations. This micro-chip simulated Wolfcamp shale with two distinct regions: (i) a high-permeability fracture zone (20 µm pore size) interconnected to (ii) a low-permeability nano-network zone (100 nm size). The fluorescent microscopy technique was applied to visualize and quantify the performance of different flowback enhancers during injection and flowback processes. This study highlights results from the nanofluidic analysis performed on Wolfcamp Formation rock specimens using a microreservoir-on-a-chip, which showed the benefits of the multi-functionalized surfactant (MFS) in terms of enhancing oil/condensate production. Test results obtained at a simulated reservoir temperature of 113°F (45°C) and a testing pressure of 2,176 psi (15 MPa) showed a significant improvement in relative permeability to hydrocarbon (k _ro) in the nanomodel when MFS was added to the stimulation fluids at loadings as low as 0.05% v/v. The results were compared against other premium flowback enhancers. Measurements using a high-resolution spinning drop tensiometer showed a 40-fold reduction in interfacial tension when the stimulation fluid containing MFS was tested against Wolfcamp crude at 113°F (45°C). Also, MFS outperformed other premium surfactants in Amott spontaneous imbibition analysis when tested with Wolfcamp core samples. This work used a nanofluidic model that appropriately reflected the inherent nanoconfinement of shale/tight formation to resolve the flowback process in hydraulic fracturing, and it is the first of its kind to visualize the mechanism behind this process at nanoscale. This platform also demonstrated a cost-effective alternative to coreflood testing for evaluating the effect of chemical additives on the flowback process. Conventional lab and field data were correlated with the nanofluidic analysis.

The Devonian Duvernay Formation in Alberta, characterized as a carbonate-siliceous source rock, is ramping up to be one of the largest and most prolific shale oil plays in Canada. In the southern part of the Duvernay Shale Basin (i.e. East Shale Basin), tight limestone beds are interbedded with laminated organic-rich calcareous shales, which show an organic maturity ranging mostly from early oil- to condensate-window. This new light oil shale play is still in the initial stages of development and the nature of these deposits requires hydraulic fracturing to increase stimulated rock volume. General completion programs involve ≥50 clustered plug ‘n’ perf stages with slickwater treatments in excess of 40,000 m³ with ~4000 tonnes of proppant per well. The large water volume treatments will inevitably interact directly with the rock surface in the stimulated area and cause both oil-water and rock-water interactions. Post-hydraulic fracturing water retention is especially pronounced in light oil shale plays. The oil-wet nature of the Duvernay, along with calcareous and siliceous shale lithologies, adds to the complexity of water retention and perceived water-blockage. In addition, because of operational delays such as road bans and pipeline constraints, some wells may be shut-in after the fracturing treatment for weeks and even months, which will affect rock-oil-water behavior (i.e. production). The extent of water displacing into the matrix of the rocks of the Duvernay Formation in the East Shale Basin, as measured by load fluid recovery, varies significantly and appears to heavily rely on the choice of surfactant. Although the use of surfactants is generally accepted for this play, detailed understanding of the rock-fluid interaction mechanisms is still incomplete. This paper investigated the response of Duvernay Shale rocks from the East Shale Basin to various types of surfactants and analyzed production and fluid flowback data. Amott Cell analyses, which test for spontaneous oil displacement using various stimulation fluid types, demonstrated that in the East Shale Basin, nano-sized surfactants including multi-functional surfactants (MFS) and microemulsions significantly outperformed common surfactant chemistry when tested with mixed wettability shale core samples. The results provide an estimate as to extent of water migration into the matrix of the Duvernay as a result of the choice of surfactant. Our analysis is made possible from publicly available cores, laboratory analysis and high quality well production data from the Alberta Energy Regulator.

Organic soils or Histosols or peats as they are commonly referred to, are characterized by the presence of large amounts of organic soil materials (OSM), which is commonly quantified by the Walkley and Black (1934) (WB) method to determine the soil organic matter (SOM) using a correction factor of 1.724. SOM of Histosols is also identified through a combustion (loss on ignition, LOI) or elemental C-analysis (with a carbon-nitrogen-sulfur (CNS) analyzer with combustion and gas density detector). These methods were established using temperate and boreal peat deposits and here we demonstrate that tropical peat deposits require a modified approach. Typical SE-Asian tropical lowland peat pedons from rain forest and oil palm settings were sampled and the material analysed using a CNS analyzer, WB-C and LOI. The ratios for LOI:CNS-C for the 20 samples yielded values between 2.00–3.09 with a mean of 2.50 while the LOI:WB-C ratio yielded values from 1.75 to 2.58 with a mean of 1.94. A comparison of these values for topsoils and subsoils showed mean ratios (LOI:WB-C) of 1.94 and 1.89 for topsoils and subsoils, respectively. The forest samples had higher LOI:WB-C ratios than the subsoils from oil palm settings (1.94 vs 1.84). These values suggest that the standard factor of 1.724 to correct OSM to SOM for tropical soils is untenable. The values to convert CNS and WB-C values of tropical topsoils/subsoils to SOM or LOI should be 2.5 or 1.9, respectively. Our results indicate a significant difference in the soil organic carbon (SOC) of tropical lowland peats depending on the method used.