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Cadmium mercury selenide (CdHgSe) nanocrystals exhibit a unique combination of low-energy optical absorption and emission, which can be tuned from the visible to the infrared range through both quantum confinement and adjustment of their composition. Owing to this advantage, such nanocrystals have been studied as a promising narrow-band infrared light emitter. However, the electroluminescence of CdHgSe-based nanocrystals has remained largely unexplored, despite their potential for emitting light in the telecom wavelength range. Further benefits to their optical properties are expected from their shape control, in particular the formation of 2D nanocrystals, as well as from a proper design of their heterostructures. In this work, a colloidal synthesis of CdHgSe/ZnCdS core/shell nanoplatelets (NPLs) starting from CdSe template NPLs employing a cation exchange strategy is developed. The heterostructures synthesized exhibit photoluminescence that can be tuned from ≈1300 to 1500 nm. These near-infrared-active NPLs are employed in light-emitting diodes, demonstrating low turn-on voltage and high external quantum efficiency.

Luminescent Quantum dots (QDs) have gathered significant attention over the past decade. Their distinct chemical and optical properties, including size-adjustable light emission, remarkable photostability, and a range of fluorescence colors, have motivated extensive investigations. In recent years, near-infrared (NIR) quantum dots have emerged as a promising avenue for a new generation of optoelectronic devices including infrared detectors and light sources. This study presents the fabrication of NIR-LEDs operating at the o-band optical telecommunication wavelength (1300 nm) using novel CdHgSe/ZnCdS core/shell nanoplatelets with a photoluminescence quantum yield of 70%. The nanoplatelets achieve a remarkable external quantum efficiency (EQE) of 7% in the final device. Notably, the resulting EQE of the fabricated NIR-LED sets a new benchmark for mercury-based QD LEDs.

We examine whether bedding thickness or constitutive properties correlate with the spacing of equally spaced shear-enhanced compaction bands and compactional shear bands in Miocene sandstones of the Whakataki Formation, North Island, New Zealand. Quantitative spacing analysis reveals a positive correlation between bedding thickness and the spacing of strata-bound deformation bands, as is commonly observed for veins, joints, and normal faults. The observed spacing to thickness ratio (STR) ranges from 0.02 to 0.14 and is considerably smaller than observed for veins, joints, and normal faults (usually ≥ 1). Modelling compaction bands as stiff tabular inclusions in a layered sequence, simple elastostatic numerical simulations show that they act as stress amplifiers, which may explain STR ≪ 1. Additionally, we obtained laboratory estimates of rock permeability and strength to test if the constant band spacing can be explained with a constitutive instability proposed for compaction bands: the stationary cnoidal wave. The results from this study indicate that this model fails to explain the observed spacing if we use the material properties obtained in the laboratory. This discrepancy likely arises from the following: [1] laboratory estimates of host-rock properties are not the same as those at depth; [2] the used semi-analytical solution for the stationary cnoidal wave employs an incorrect value (m = 3) of the stress exponent; and [3] the equation does not account for coupled layered media. While we cannot conclusively falsify the cnoidal-wave model for compaction band spacing per se, it appears likely that the existing solution should not be used for predicting band spacing in layered porous sandstones.

Wettability of CO2/brine/clay is one of the most important parameters in assessing CO2 storage capacities and containment security. Despite its importance, the literature data in this context are very limited. We thus systematically measured montmorillonite, illite, and kaolinite wettability for CO2/brine, nitrogen/brine, and nitrogen/oil systems at various pressures (5, 10, 15, and 20 MPa) and temperatures (305 and 333 K). The zeta potential of each clay mineral was also measured to investigate its link to the macroscopic contact angle. The results show that both advancing and receding water contact angles for CO2/brine, nitrogen/brine, and nitrogen/oil systems increase with an increase in pressure. However, they are only slightly reduced by increasing temperature. It was also shown that montmorillonite has a higher water contact angle in the presence of CO2, followed by illite and kaolinite. The same trend was measured for nitrogen/brine and brine/oil systems. Consequently, montmorillonite is strongly oil-wet; kaolinite and illite, however, are strongly water-wet at typical storage conditions (high pressure and elevated temperature). This has important implications for CO2 geostorage in determining the flow of CO2 and its entrapment, fluid spreading, and dynamics in the reservoir.

Wettability of CO2/brine/clay is one of the most important parameters in assessing CO2 storage capacities and containment security. Despite its importance, the literature data in this context are very limited. We thus systematically measured montmorillonite, illite, and kaolinite wettability for CO2/brine, nitrogen/brine, and nitrogen/oil systems at various pressures (5, 10, 15, and 20 MPa) and temperatures (305 and 333 K). The zeta potential of each clay mineral was also measured to investigate its link to the macroscopic contact angle. The results show that both advancing and receding water contact angles for CO2/brine, nitrogen/brine, and nitrogen/oil systems increase with an increase in pressure. However, they are only slightly reduced by increasing temperature. It was also shown that montmorillonite has a higher water contact angle in the presence of CO2, followed by illite and kaolinite. The same trend was measured for nitrogen/brine and brine/oil systems. Consequently, montmorillonite is strongly oil-wet; kaolinite and illite, however, are strongly water-wet at typical storage conditions (high pressure and elevated temperature). This has important implications for CO2 geostorage in determining the flow of CO2 and its entrapment, fluid spreading, and dynamics in the reservoir.

© 2018 Elsevier Ltd Changes in effective stress around a borehole due to pressure drop can cause formation instabilities leading to issues such as sand/solid production and wellbore stability. Analytical studies have been conducted in the past to gain insights into physical mechanisms involved in this complex process. The developed analytical solutions for such hydro-mechanical instability often consider perfectly plastic behaviour for the rock, whereas the field observations suggest strong strain softening as a result of pore pressure drop. In addition, these analytical solutions are not verified with experimental data in many instances. In this study, we developed a series of closed form solutions to predict the stress and strain changes around a borehole within poro-elasto-softening-plastic concept using Mohr Coulomb failure criterion. For the purpose of describing the pore pressure induced softening behaviour; an exponential function was used to relate the evolution of yield surface to plastic shear strain. In a further step, a series of hollow cylinder experiments were conducted on sandstone samples where different hydrostatic confinements at elevated pore pressures were applied. The hollow cylindrical samples were imaged before and after the experiments using 3D X-ray micro Computed Tomography technique (micro-CT) to precisely identify the collapsed-damaged and plastic zones formed around the borehole. Finally, the results from the experiments and micro-CT analysis were compared with the model prediction and a good agreement was observed.

Wettability of CO2/brine/clay is one of the most important parameters in assessing CO2 storage capacities and containment security. Despite its importance, the literature data in this context are very limited. We thus systematically measured montmorillonite, illite, and kaolinite wettability for CO2/brine, nitrogen/brine, and nitrogen/oil systems at various pressures (5, 10, 15, and 20 MPa) and temperatures (305 and 333 K). The zeta potential of each clay mineral was also measured to investigate its link to the macroscopic contact angle. The results show that both advancing and receding water contact angles for CO2/brine, nitrogen/brine, and nitrogen/oil systems increase with an increase in pressure. However, they are only slightly reduced by increasing temperature. It was also shown that montmorillonite has a higher water contact angle in the presence of CO2, followed by illite and kaolinite. The same trend was measured for nitrogen/brine and brine/oil systems. Consequently, montmorillonite is strongly oil-wet; kaolinite and illite, however, are strongly water-wet at typical storage conditions (high pressure and elevated temperature). This has important implications for CO2 geostorage in determining the flow of CO2 and its entrapment, fluid spreading, and dynamics in the reservoir.

Gas sorption in coal, in particular CO2, is known to cause swelling and internal structural change or damage. For instance, CO2 adsorption on coal causes swelling which in turn can close the fractures or cleats whereas its desorption can open pre-existing fractures as well as create new fractures, thus enhancing gas flow paths in coal seams. Gas release and the associated induced damage are relevant for several applications such as coal burst in coal mining operations and for geological sequestration of CO2 into coal seams to reduce both the carbon footprint and increase the efficiency of energy extraction. However, the sorption-induced internal structural damage in coal, in particular the link between the micro-scale damage phenomena to macro-scale processes in confined and unconfined stress states, is not yet fully understood.We carried out a series of experiments to study the potential sorption-induced damage in both confined and unconfined stress states at micro (μm) and macro (cm) scale. 3D images, obtained by X-ray microcomputed tomography (micro-CT) technique, showed that in the unconfined stress state, adsorption of CO2 closes some pre-existing fractures while new fractures form in the specimen of coal. This is well supported by high pressure CO2 adsorption analyses that were independently conducted. After CO2 release, the overall fracture intensity, defined as the area of fractures per volume of rock mass, was considerably increased by opening both pre-existing fractures together with new fractures. In the confined condition, the gas adsorption was significantly lower confirming the closure of the initial fractures by swelling without creation of induced fractures. However, the gas release under shearing stress was significantly higher showing that the shearing stress causes further damage assisted by gas release and its induced micro-structural damage.

Gas sorption in coal, in particular CO2, is known to cause swelling and internal structural change or damage. For instance, CO2 adsorption on coal causes swelling which in turn can close the fractures or cleats whereas its desorption can open pre-existing fractures as well as create new fractures, thus enhancing gas flow paths in coal seams. Gas release and the associated induced damage are relevant for several applications such as coal burst in coal mining operations and for geological sequestration of CO2 into coal seams to reduce both the carbon footprint and increase the efficiency of energy extraction. However, the sorption-induced internal structural damage in coal, in particular the link between the micro-scale damage phenomena to macro-scale processes in confined and unconfined stress states, is not yet fully understood.We carried out a series of experiments to study the potential sorption-induced damage in both confined and unconfined stress states at micro (μm) and macro (cm) scale. 3D images, obtained by X-ray microcomputed tomography (micro-CT) technique, showed that in the unconfined stress state, adsorption of CO2 closes some pre-existing fractures while new fractures form in the specimen of coal. This is well supported by high pressure CO2 adsorption analyses that were independently conducted. After CO2 release, the overall fracture intensity, defined as the area of fractures per volume of rock mass, was considerably increased by opening both pre-existing fractures together with new fractures. In the confined condition, the gas adsorption was significantly lower confirming the closure of the initial fractures by swelling without creation of induced fractures. However, the gas release under shearing stress was significantly higher showing that the shearing stress causes further damage assisted by gas release and its induced micro-structural damage.

Copyright 2018, Society of Petroleum Engineers Despite decades of numerical, analytical and experimental researches, sand production remains a significant operational challenge in petroleum industry. Amongst all techniques, analytical solutions have gained more popularity in industry applications because the numerical analysis is time consuming; computationally demanding and solutions are unstable in many instances. Analytical solutions on the other hand are yet to evolve to represent the rock behaviour more accurately. We therefore developed a new set of closed-form solutions for poro-elastoplasticity with strain softening behaviour to predict stress-strain distributions around the borehole. A set of hollow cylinder experiments was then conducted under different compression scenarios and 3D X-Ray Computed Tomography was performed to analyse the internal structural damage. The results of the proposed analytical solutions were compared with the experimental results and good agreement between the model prediction and experimental data was observed. The model performance was then tested by analysing the onset of sand production in a well drilled in Bohai Bay in Northeast of China. Acoustic and density log along with core data were used to provide the input parameters for the proposed analytical model in order to predict the potential sanding in this well. The proposed solution predicted the development of a significant plastic zone thus confirming sand production observed by today sanding issue in this well.

Copyright © 2018 ARMA, American Rock Mechanics Association. Previous studies show that the effective fracture toughness will increase with the rise of rock ductility during the hydraulic fracture propagation. Higher pump horsepower is required for fracture propagation and stimulation volume will decrease extensively. However, such conclusion was mainly validated by numerical modeling and field observation with much fewer experimental investigations. Three different sample types of silica-rich, calcite-rich, and clay-rich with distinct ductility was made. Mineralogy and clay content have a profound effect on ductility. Mechanical properties and ductility were measured and compared using UCS, Brazilian, semicircular bending toughness, and hydraulic fracturing tests. Hydraulic fracturing tests were conducted on cube of 10cm on true triaxial stress condition. Also, scaling laws were applied to simulate the field-like viscosity dominated propagation condition. A direct relation between sample ductility and lag time (between the fracture initiation and breakdown) was observed (i.e. longer lag time for samples with higher ductility). In addition, it was shown that ductile samples have slower fracture propagation.

Understanding the mechanical properties of shaly sandstone is of great importance in reservoir geomechanics. Because of the lack of core data, measurements based on acoustic wave velocities are often conducted. In such measurements, the mechanical properties such as uniaxial compressive strength (UCS) and Young's modulus (E) are related to the porosity of sandstone and shaly sandstone. However, in many instances, the porosity fails to directly correlate to mechanical properties especially when dispersed clays are present. Therefore, in this study, a set of uniaxial compressive tests on a number of different shaly sandstones was performed. The X-ray computed tomography was conducted on the representative samples from each type of sandstone to assess the porosity, rock composition, and texture. Independent compositional analysis was also carried out on all representative samples to link the samples' composition to their microstructure. Interestingly, it was found that the mechanical properties of these shaly sandstones are well-correlated to the combined clay volume and effective porosity in a multivariate analysis. It was concluded that the univariate analysis solely performed on porosity cannot always correlate well to the mechanical properties of sandstone containing clays. Therefore, a combination of clay volume and effective porosity is more accurately correlated to mechanical properties.

Hypothesis: Wettability plays an important role in underground geological storage of carbon dioxide because the fluid flow and distribution mechanism within porous media is controlled by this phenomenon. CO 2 pressure, temperature, brine composition, and mineral type have significant effects on wettability. Despite past research on this subject, the factors that control the wettability variation for CO 2 /water/minerals, particularly the effects of pores in the porous substrate on the contact angle at different pressures, temperatures, and salinities, as well as the physical processes involved are not fully understood. Experiments: We measured the contact angle of deionised water and brine/CO 2 /porous sandstone samples at different pressures, temperatures, and salinities. Then, we compared the results with those of pure quartz. Finally, we developed a physical model to explain the observed phenomena. Findings: The measured contact angle of sandstone was systematically greater than that of pure quartz because of the pores present in sandstone. Moreover, the effect of pressure and temperature on the contact angle of sandstone was similar to that of pure quartz. The results showed that the contact angle increases with increase in temperature and pressure and decreases with increase in salinity.

© 2017 American Rock Mechanics Association (ARMA). All rights reserved. While rock strength is an important input parameter in geotechnical engineering, the size effect of intact rock samples on strength has long been recognised as an issue. Conventionally, it has been believed that increase in size leads to decrease in strength. A few investigations have reported different trend to that consider conventionally where the uniaxial compressive strength (UCS) follows ascending and descending behaviour. Masoumi et al. [1] investigated this behaviour from analytical and experimental viewpoints that resulted in the formulation of the unified size effect law (USEL) which accounts for the reverse size effect behaviour of intact rocks. A limitation of the current USEL is that at very large sizes, the UCS prediction by USEL tends to zero. This paper outlines an improvement to USEL to overcome this limitation based on the multifractal theory. Attributes of the improved USEL model were highlighted and verified using UCS data from different rock types. Finally, it was demonstrated that there is a good agreement between the improved USEL prediction and the experimental results.

Permeability variation is one of the key factors influencing the injectivity of CO 2 in CO 2 sequestration projects. Despite the research carried out on the subject, the results are highly inconsistent. In this study, the injection of brine (5 wt % NaCl + 1 wt % KCl), CO 2 -saturated (live) brine, and supercritical CO 2 was performed on three homogeneous Berea sandstone plugs with a low clay content and two Bandera Gray sandstone plugs with a high clay content at reservoir conditions (10 MPa and 323 K). Porosity and permeability of the samples were measured using nuclear magnetic resonance (T 2 relaxation time), and a dynamic (during flooding) permeability measurement technique, respectively, at different injection rates and injection durations. The mercury intrusion test was also performed on each sample to further evaluate its pore throat size distributions. From the results of this study, it was revealed that the CO 2 injection rate is unlikely to affect the permeability significantly. It was also shown that the permeability can be influenced depending upon sandstone pore throat size distribution and the distribution/structure of the clay minerals in the sample.

Increasing energy demand and associated global warming are unarguably the two major challenges that the world currently faces. One of the ideas to reduce the carbon footprint while increasing the efficiency of the energy extraction is CO 2 sequestration in coal seams. This can additionally enhance the coal-bed methane production. However, this process depends on many factors, among which coal wettability is of particular importance especially because of its pressure and temperature dependency. To evaluate this process, coal wettability was tested by measuring the contact angle of CO 2 and water as a function of pressure, temperature, and salinity (DI water and brine (5 wt % NaCl + 1 wt % KCl), i.e., wt % is the weight percentage of salt to water. The results show that the CO 2 -water contact angle increases significantly, with increasing pressure, temperature, and salinity indicating more-effective CO 2 wetness of coal. This, in turn, can reduce the CO 2 residual trapping capacities and increase methane recovery. Furthermore, we demonstrated that CO 2 density correlates well with coal wettability.

The water contact angle in a system of brine (20 wt % CaCl 2 ) and CO 2 was measured on a smooth dolomite surface [root mean square (RMS) surface roughness of 45 nm] with both hydrophilic and hydrophobic behaviors as a function of the pressure (0.1, 5, 10, 15, and 20 MPa) and temperature (308, 323, and 343 K). The experimental results show that the contact angle of brine/CO 2 increases slightly with the temperature when the dolomite surface is hydrophilic but, interestingly, reduces when the surface is hydrophobic. The results also illustrate that the brine/CO 2 contact angles increase with increasing pressure. We interpreted the experimental observations using the concept of alteration in van der Waals potential (substrate surface chemistry) with thermodynamic properties, including pressure and temperature.

A new method was developed for analysing and delineating streambed water fluxes, flow conditions, and hydraulic properties using coiled fibre-optic distributed temperature sensing (FO-DTS) or closely-spaced discrete temperature sensors. This method allows for a thorough treatment of the spatial information embedded in temperature data by creating a matrix visualisation of all possible sensor pairs. Application of the method to a 5-day field dataset reveals the complexity of shallow streambed thermal regimes. To understand how velocity estimates are affected by violations of assumptions of 1-D, saturated, homogeneous flow and to aid in the interpretation of field observations, the method was also applied to temperature data generated by numerical models of common field conditions: horizontal layering, presence of lateral flow and variable streambed saturation. The results show that each condition creates a distinct signature visible in the triangular matrices. The matrices are used to perform a comparison of the behaviour of 1-D analytical heat-tracing models. The results show that the amplitude ratio-based method of velocity calculation leads to the most reliable estimates. The minimum sensor spacing required to obtain reliable velocity estimates with discrete sensors is also investigated using field data. The developed method will aid future heat-tracing studies by providing a technique for visualizing and comparing results from FO-DTS installations and testing the robustness of analytical heat-tracing models.

Several processes have been proposed to describe the low recovery of hydraulic fracturing fluid in unconventional shale reservoirs which has caused both technical and environmental concerns. This study describes novel hydraulic experiments to quantitatively investigate the kinetics of water uptake into partially saturated shale through investigating the pressure response of injecting fluids (NaCl, KCl, MgCl2, and CaCl2 with different ionic concentrations) into crushed and sieved shale fragments. The results of the study indicate that the cumulative water uptake under pressure is likely to be controlled by three processes: surface hydration, capillary hydration including advective flow, and osmotic hydration. Each of these processes is a function of the differences between the in situ pore fluid and the injection fluid (solution chemistry and concentration) and the shale physicochemical properties, in particular the contact surface area, pore diameter, and the Cation Exchange Capacity (CEC). The uptake is not instantaneous, but is diffusion limited, with the rate governed by a number of kinetic processes. Uptake proceeds in three stages, each associated with a different process: (1) predominantly surface hydration, (2) predominantly capillary hydration and finally, (3) predominantly osmotic hydration. It was also shown that shale can take up a significant amount of water compared to its available solid volume. However, contrary to the conventional understanding, the increase in salinity of the injection fluid does not necessarily lead to reduced water uptake into shales, but is dependent on the type and concentration of cations within the shale and injecting fluid.

Total rock porosity is a key parameter in a wide range of disciplines from petroleum to civil and mining engineering. Porosity is particularly important in petroleum engineering applications, e.g., from estimation of hydrocarbon in place to prediction of geomechanical properties. Conventional techniques used to measure the total porosity, i.e., mercury intrusion, nitrogen physisorption, focused ion beam–scanning electron microscopy (FIB–SEM), nuclear magnetic resonance (NMR) spectroscopy, gas porosimetry, and X-ray micro-/nano-computed tomography (micro-CT), have yielded inconsistent results for unconventional shale gas samples. A new robust yet practical method is thus required for measuring total porosity in tight formations to be added to the toolbox of the porosity measurement. We propose and develop here a new technique using the concept of heat transfer in porous media. This new heat technique route (HTR) was tested on a highly homogeneous Gosford sandstone benchmark to evaluate its reliability and repeatability in estimation of the total porosity. An excellent agreement was found with the conventional mercury intrusion, gas porosimetry, and micro-CT imaging techniques. Subsequently, the total porosity of an organic-rich shale sample was measured using the HRT method and compared to the conventional techniques of nitrogen physisorption–mercury intrusion and FIB–SEM techniques. Finally, a Monte Carlo analysis was performed on heat transfer measurements, proving its robustness for total porosity measurements.

Wettability is one of the most important parameters in multiphase flow through porous rocks. However, experimental measurements or theoretical predictions are difficult and open to large uncertainty. In this work we demonstrate that gas densities (which are much simpler to determine than wettability and typically well known) correlate remarkably well with wettability. This insight can significantly improve wettability predictions, thus derisking subsurface operations (e.g., CO2 geostorage or hydrocarbon recovery), and significantly enhance fundamental understanding of natural geological processes.

The structure of the fracture network formed by hydraulic fracturing operation is one of the key parameter in production from unconventional shale reservoirs. The standard approach to obtain such information is usually through well-testing coupled with micro-seismic monitoring. Unfortunately, the micro-seismic mapping is not always carried out and the conventional well-test techniques often fall short in describing the flow in shale reservoir in particular the contact area of the fractures open to flow. The other alternative technique to get insight into structure of the fracture network is to use chemical tracer tests. In this study, we propose a new simple and cost efficient technique to estimate the fracture contact area by tracking the major exchange cations in shale reservoirs. The idea behind the proposed technique is to replace the major cations on fracture surfaces in shale by increasing the concentration of one of the major cation in fracturing fluid. The current technique is satisfied the industry standard practice as the high concentrated K+ is part of hydraulic fracturing fluid composition and therefore cation exchange with other major cations (Na+, Ca++ and Mg++) is expected to occur. In order to test the feasibility of the proposed techniques, a set of laboratory tests were conducted where a shale sample was milled and sieved to three different sizes to have different contact area. They are then placed in a high pressure cylinder (built for this study) and were washed by concentrated NaCl solution under high pressure and controlled temperature. The effluent was collected successively and analysed for major cations using ICP-MS. Correlation relating the cation exchange mass content to contact surface is proposed and calibrated using the data obtained from laboratory tests.