Sandstone Core Samples Research Articles

Adsorption behavior of in-house developed CO2-philic anionic surfactants

Incorporating CO2-philic functionalities into surfactant structure is proposed to address the drawbacks of conventional foaming agents such as premature rupture of lamellae in contact with oil, surfactant loss due to adsorption on rock or partitioning between oil and water, and salinity and temperature tolerance issues. Increased activity at the gas/water interface and less surfactant adsorption to the rock due to the presence of CO2-philic chains results in higher foam durability in the presence of oil. In the present paper, a comprehensive study on the adsorption of anionic CO2-philic surfactants onto sandstone rock surface is performed to understand adsorption mechanisms through the addition of CO2-philic tail groups in surfactant structure by observing the changes in concentration, static adsorption, and point of zero charge measurements. The static adsorption tests, Fourier Transform Infrared, and the X-ray Photoelectron Spectroscopy techniques were employed to investigate the interaction of surfactants with crushed Berea sandstone core sample at 90 °C. The static adsorption values of the S (single-tail), D (double-tail), and T (triple-tail) anionic surfactants were reported to be 0.53, 0.40, and 0.6 mg /g, respectively. The effect of alkali on the adsorption process of surfactants was also investigated and the adsorption of synthesized surfactants was found significantly low in alkaline conditions. A variety of analyses, including model fitting along with kinetics and thermodynamics studies at 30, 40, and 50 °C were performed to predict the adsorption behavior. The adsorption isotherm was found to best fit in Langmuir model. The process showed the best fit in the pseudo-second-order reaction kinetics model. The spontaneity of the adsorption process was verified by thermodynamic feasibility studies of the process.

Evaluation of CO2/Water Imbibition Relative Permeability Curves in Sandstone Core Flooding—A CFD Study

Greenhouse gases such as CO2 can be safely captured and stored in geologic formations, which in turn can reduce the carbon imprint in the Earth’s atmosphere and therefore help toward reducing global warming. The relative permeability characteristics in CO2/brine or CO2/water systems provide insight into the CO2 trapping efficacy of formations such as sandstone rocks. In this research, CO2/water imbibition relative permeability characteristics in a typical sandstone core sample are numerically evaluated. This work uses transient computational fluid dynamics (CFD) simulations to study relative permeability characteristics, and a sensitivity analysis is performed based on two different injection pressures and absolute permeability values of the sandstone rock material. Results show that when the irreducible water fraction remains unchanged, the imbibition relative permeability to the non-wetting phase decreases with an increase in injection pressure within the sandstone core sample. Also, with the irreducible water fraction being unchanged, relative permeabilities to both non-wetting and wetting phases decrease with an increase in the absolute permeability of the rock material. Finally, at irreducible water saturation, relative permeability to the gas phase decreases with an increase in injection pressure.

Investigation of gas residuals in sandstone formations via X-ray core-flooding experiments: Implication for subsurface hydrogen storage

The production and utilization of hydrogen (H2) as a clean energy source offer a promising solution towards achieving net-zero carbon emissions. Utilizing sandstone formations for geological hydrogen storage presents a viable option for the practical implementation of the hydrogen economy, offering both safe and large-scale containment capabilities. Accurate assessment of gas displacement behavior in porous media plays a critical role in understanding gas saturation, gas residual, and long-term storage duration. However, there are limited studies available on dynamic displacements for hydrogen storage applications. This study aims to enhance the understanding of gas flow behavior in sandstone rocks for different gas types and determine the role of capillary pressure and gas wettability during hydrogen storage. A series of gas core-flooding experiments are performed on a brine-saturated sandstone core sample using three different gases (CO2, CH4, and H2). X-ray scanning technique is applied to detect the gas saturation and gas residual after the core-flooding experiments. The results indicate that the average gas saturation ranges between 25 and 40%, with zero gas residual for all gases, suggesting that the gas residuals in this clean sandstone sample are unaffected by the gas type. Initially, the capillary pressure profile for the sample displayed low brine saturation at 200 psi, indicating very low capillary pressure in the sample due to the high permeability and large pore radius, despite the strong water-wetting behavior of the sample. Moreover, the obtained results indicate the high potential for gas recovery (especially for hydrogen during withdrawal cycles), and the high displacement efficiency in sandstone rocks. The reported low gas residual suggests that the wettability of the rock is not affected by gas injection, and it appears that the wettability and capillary pressure are not the controlling factors for gas storage in this sandstone sample. This observation suggests that the structural trapping mechanism is most likely to be the dominant trapping mechanism in this shallow high permeable sandstone rock. Also, the injection of cushion gases such as CO2 and CH4 indicated similar results to hydrogen injection, due to the low capillary pressure and high permeability in this sandstone sample. The findings of this study can greatly enhance the understanding of gas injection, displacement behavior, and gas residuals in sandstone rocks related to underground hydrogen storage.

Charakterystyka złoża piaskowca prekenomainskiego: Środkowy Synaj, Egipt

Fifty-one sandstone core samples obtained from wadi Saal area. They are belonging to the Pre-Cenomanian age. These samples were subjected to various laboratory measurements such as: density, porosity, permeability, electrical resistivity, grain size analysis and ultrasonic wave velocity. The parameters describing reservoir properties are outlined. Packing index, reservoir quality index, flow zone indicator and pore throat radius (R35 and R36) were calculated. The obtained interrelationships among these parameters allowing to improve petrophysical knowledge about the Pre-Cenomanian reservoir information. The obtained rock physics models could be employed with some precautions to the subsurface existences of the Pre-Cenomanian sandstone reservoirs especially in the surrounding areas.

Stress sensitivity mechanism of pores in unconsolidated sandstone reservoir using NMR technology

Unconsolidated sandstone reservoirs exhibit low cementation strengths. With change in the effective stress state of the reservoir, stress sensitivity damage is induced. Consequently, the crude oil productivity is affected and the overall recovery efficiency of the reservoir decreases. Hence, a systematic investigation of the stress sensitivity of unconsolidated sandstone is crucial for the efficient development of unconsolidated sandstone reservoirs. This study primarily employed nuclear magnetic resonance (NMR) to conduct stress-sensitivity experiments on unconsolidated sandstone core samples. It quantitatively characterized the dynamic changes in the damage index of pore sensitivity in unconsolidated sandstone cores under different confining pressures. This research elucidated the stress sensitivity characteristics of unconsolidated sandstone cores during the process of increasing confining pressure. The results of the laboratory study indicated a positive correlation between the experimental confining pressure and stress sensitivity index of the core samples. During the initial stages of increasing confining pressure, the stress sensitivity index increased. With continued increase in the confining pressure, the stress sensitivity damage index for smaller pore throats ranged as 4.18–30.08%, whereas the stress sensitivity damage index for medium pore throats ranged as 4.15–28.45%. Stress sensitivity primarily occurred in smaller and medium pore throats during a progressive increase in the confining pressure. The degree of stress sensitivity was positively correlated with the scale of reservoir pore-throat development, with highly permeable reservoirs experiencing a greater extent of stress sensitivity damage. The statistical results provide crucial support for optimizing mining field production systems, effectively controlling reservoir damage, and achieving the efficient development of unconsolidated sandstone reservoirs.

Streaming Potential Experiment on Sandstone Core Samples Based on Current Source Model under Different Sodium Chloride Solutions.

The streaming potential effect has a wide range of applications in geophysics. The core streaming potential experiment requires that there is no external circuit at both ends of the core, but a measurement circuit must be introduced to measure the voltage between both ends of the core which will cause an external circuit. In order to analyze the effect of measurement circuits on the streaming potential experiment, this paper proposes a core current source model, i.e., the core in the streaming potential experiment is regarded as a circuit composed of a current source whose output current is equal to the seepage current and the core resistance. By changing the resistance value of the external circuit, it is found that the seepage current is not affected by the external resistance but by the excitation pressure. Experiments on the streaming potential of 20 sandstone cores under distilled water, 0.01 mol/L, 0.02 mol/L, 0.05 mol/L, 0.1 mol/L, 0.2 mol/L, 0.4 mol/L, and 0.6 mol/L sodium chloride solutions revealed that the effect of the external circuit on the streaming potential signal increased with decreasing mineralization. For distilled water-saturated sandstone cores, the effect of the external circuit was about 2%.

Real-Size Reconstruction of Porous Media Using the Example of Fused Filament Fabrication 3D-Printed Rock Analogues

The multi-scale study of rock properties is a necessary step in the planning of oil and gas reservoir developments. The amount of core samples available for research is usually limited, and some of the samples can be distracted. The investigation of core reconstruction possibilities is an important task. An approach to the real-size reconstruction of porous media with a given (target) porosity and permeability by controlling the parameters of FFF 3D printing using CT images of the original core is proposed. Real-size synthetic core specimens based on CT images were manufactured using FFF 3D printing. The possibility of reconstructing the reservoir properties of a sandstone core sample was proven. The results of gas porometry measurements showed that the porosity of specimens No.32 and No.46 was 13.5% and 12.8%, and the permeability was 442.3 mD and 337.8 mD, respectively. The porosity of the original core was 14% and permeability was 271 mD. It was found that changing the layer height and nozzle diameter, as well as the retract and restart distances, has a direct effect on the porosity and permeability of synthetic specimens. This study shows that porosity and permeability of synthetic specimens depend on the flow of the material and the percentage of overlap between the infill and the outer wall.

Implementation of a non-destructive method to assess weathering deterioration of sandstones in cultural heritage

This paper proposes a non-destructive approach based on the Equotip hardness tester to assess weathering deterioration in a protected sandstone monument located in the historic centre of Camerino (Italy). The approach is tested on one sandstone column, where various forms of weathering, such as discolouration, scaling and loss of stone volume, are observed. The mechanical characterisation with Equotip was performed on 24 measuring points, systematically distributed in the column. Innovatively, the two probes available from Proceq (Proceq© 2010) were used to assess differences among surface and in-depth hardness values of the column. In addition, an un-weathered rock core from the original extraction site was also analysed and compared with the rock matrix of the column. The obtained results show a 15% hardness reduction from depth to the surface of the column and a 25% overall hardness reduction with respect to the fresh sandstone core samples. Equotip results were coupled with grain size analyses, mercury intrusion porosimetry, scanning electron microscopy and X-ray diffractometry results, and a correlation between hardness and grain size was evaluated. By combining these approaches, it was possible to identify the processes that occurred during weathering: (a) freeze-thaw cycles that caused a decrease in micropore volume and an increase in macropores connected with low Equotip values; (b) iron oxide and sulphuric acid released from pyrite oxidation contribute to the dissolution and precipitation of calcium carbonate, which can be rearranged in the outer and surface macroporosity. The quantitative approach proposed in this study may be a valid low-cost and quick tool to assess weathering heterogeneities on building stone materials and to provide insights for effective preservation strategies of historical monuments.

4D Neutron Imaging of Solute Transport and Fluid Flow in Sandstone Before and After Mineral Precipitation

AbstractIn many geological systems, the porosity of rock or soil may evolve during mineral precipitation, a process that controls fluid transport properties. Here, we investigate the use of 4D neutron imaging to image flow and transport in Bentheim sandstone core samples before and after in‐situ calcium carbonate precipitation. First, we demonstrate the applicability of neutron imaging to quantify the solute dispersion along the interface between heavy water and a cadmium aqueous solution. Then, we monitor the flow of heavy water within two Bentheim sandstone core samples before and after a step of in‐situ mineral precipitation. The precipitation of calcium carbonate is induced by reactive mixing of two solutions containing CaCl2 and Na2CO3, either by injecting these two fluids one after each other (sequential experiment) or by injecting them in parallel (co‐flow experiment). We use the contrast in neutron attenuation from time‐resolved tomograms to derive three‐dimensional fluid velocity field by using an inversion technique based on the advection‐dispersion equation. Results show mineral precipitation induces a wider distribution of local flow velocities and leads to alterations in the main flow pathways. The flow distribution appears to be independent of the initial distribution in the sequential experiment, while in the co‐flow experiment, we observed that higher initial local fluid velocities tended to increase slightly following precipitation. The outcome of this study contributes to progressing the knowledge in the domain of reactive solute and contaminant transport in the subsurface using the promising technique of neutron imaging.

Investigation of the Combination Mechanism of Spontaneous Imbibition and Water Flooding in Tight Oil Reservoirs Based on Nuclear Magnetic Resonance

As conventional oil reservoirs are gradually being depleted, researchers worldwide are progressively shifting their focus towards the development and comprehensive study of tight oil reservoirs. Considering that hydraulic fracturing is one of the main approaches for developing tight sandstone reservoirs, it is of great significance to explore the mechanism of spontaneous imbibition and waterflooding behavior after hydraulic fracturing in tight oil reservoirs. This research delves into the analysis of tight sandstone core samples obtained from the Shahejie Formation in the Bohai Bay Basin. All core samples are used for a series of experiments, including spontaneous imbibition and water flooding experiments. An additional well-shut period experiment is designed to understand the impact and operational dynamics of well shut-in procedures in tight reservoir development. Utilizing nuclear magnetic resonance (NMR) technology, the pore sizes of a sample are divided into three types, namely, macropores (>100 ms), mesopores (10–100 ms), and micropores (<10 ms), to thoroughly assess the fluid distribution and changes in fluid signals during the spontaneous imbibition and water flooding stages. Experimental outcomes reveal that during the spontaneous imbibition stage, oil recovery ranges from 12.23% to 18.70%, predominantly depending on capillary forces. The final oil recovery initially rises and then falls as permeability decreases, while the contribution of micropores progressively grows as the share of mesopores and macropores deceases. With water flooding processes carried out after spontaneous imbibition, enhanced oil recovery is observed between 28.26% and 33.50% and is directly proportional to permeability. The well shut-in procedures can elevate the oil recovery to as high as 47.66% by optimizing energy balance.

Effect of Matrix Characteristic and the Pore‐Throat Limit for Water Imbibition in Early Jurassic Tight Sandstone Reservoir of the Tuha Basin

Spontaneous imbibition (SI) is a fundamental mechanism for improving the production efficiency of tight sandstone reservoirs. Matrix characteristic plays important roles in the SI process, but how these factors affect SI and the limit pore‐throat size of effective driving force in the tight sandstone of the Tuha Basin has not been firmly established. Thus, a series of experiments (FE‐SEM, QEMSCAN, XRD, CT, and SI) of four tight sandstone core samples were conducted under laboratory conditions in the Tuha Basin. The results show that quartz and plagioclase feldspar are the main detrital minerals, while illite and illite/smectite (I/S) are the predominant clay minerals of those sandstone samples, and they have a micro‐nano (<2 μm) to meso‐macro (>10 μm) pores, but the micro‐nano pore performance disconnected, and during SI process, fluid enters small and meso‐macro‐size pores simultaneously. However, small pores play a dominant role in the initial stage (with steep imbibition slopes), while meso‐macro pores predominate in the second stage (with shallow imbibition slopes), and the limit pore‐throat value of the tight sandstone is around 9.1 μm in the Tuha Basin, beyond which the SI will be weakened. Though the mineral composition and its wettability will be changed with fluid environment (especially for clay minerals), the small pores (formed by clay minerals) always play a dominant role than meso‐macro‐size pores (mainly formed by quartz and plagioclase feldspar) in SI process. These observations can improve our understanding of fluid–reservoir interaction in the Tuha Basin’s tight sandstone reservoir and provide guidance for improving oil and gas recovery.

Phase behavior of gas condensate in porous media using real-time computed tomography scanning

The phase behavior of gas condensate in reservoir formations differs from that in pressure–volume–temperature (PVT) cells because it is influenced by porous media in the reservoir formations. Sandstone was used as a sample to investigate the influence of porous media on the phase behavior of the gas condensate. The pore structure was first analyzed using computed tomography (CT) scanning, digital core technology, and a pore network model. The sandstone core sample was then saturated with gas condensate for the pressure depletion experiment. After each pressure-depletion state was stable, real-time CT scanning was performed on the sample. The scanning results of the sample were reconstructed into three-dimensional grayscale images, and the gas condensate and condensate liquid were segmented based on gray value discrepancy to dynamically characterize the phase behavior of the gas condensate in porous media. Pore network models of the condensate liquid ganglia under different pressures were built to calculate the characteristic parameters, including the average radius, coordination number, and tortuosity, and to analyze the changing mechanism caused by the phase behavior change of the gas condensate. Four types of condensate liquid (clustered, branched, membranous, and droplet ganglia) were then classified by shape factor and Euler number to investigate their morphological changes dynamically and elaborately. The results show that the dew point pressure of the gas condensate in porous media is 12.7 MPa, which is 0.7 MPa higher than 12.0 MPa in PVT cells. The average radius, volume, and coordination number of the condensate liquid ganglia increased when the system pressure was between the dew point pressure (12.7 MPa) and the pressure for the maximum liquid dropout, Pmax (10.0 MPa), and decreased when it was below Pmax. The volume proportion of clustered ganglia was the highest, followed by branched, membranous, and droplet ganglia. This study provides crucial experimental evidence for the phase behavior changing process of gas condensate in porous media during the depletion production of gas condensate reservoirs.

Wettability Alteration of Berea Sandstone for Gas Condensate Applications.

Gas condensate reservoirs can suffer significant decreases in production due to the buildup of liquid in the vicinity of the wellbore, which occurs when the bottom-hole flowing pressure drops below the dew point pressure. Consequently, the generated liquid hydrocarbons can hinder the movement of the produced gas by adhering to the surfaces, thereby creating a condensate bank. One potential method for mitigating the issue of condensate banking involves the injection of chemical treatment and the alteration of wettability from a liquid-wet state to an intermediate gas-wet state. This study conducted an experimental investigation of the impact of fluorochemical treatment on altering the wettability from liquid-wetting to intermediate gas-wetting. The wettability of the Berea sandstone was analyzed before and after chemical treatment over a temperature range of 25-83 °C. The outcrop core samples of Berea sandstone used in this investigation exhibited an average porosity and permeability of 20% and 100 mD, respectively. The experimental results indicate that the application of chemical treatment has the potential to alter the wettability of Berea sandstone, transitioning it from a state of liquid-wetting to gas-wetting at standard temperatures. The chemical treatment alters the wettability from liquid-wet to intermediate gas-wet at higher temperatures. Furthermore, the alteration of wettability substantially improves the mobility of the oil phase and decreases the residual saturation of the oil, thereby aiding the reduction of liquid accumulation around the wellbore. According to this research, altering the wettability of the rock surrounding the wellbore in gas condensate reservoirs from a state of strong liquid-wet to gas-wet has the potential to enhance the deliverability of gas wells and improve injectivity in the field.

Model of shear strength of ultra-deep fractured sandstone considering fracture morphology

Ultra-Deep fractured tight sandstone gas reservoir, the hotpot unconventional petroleum resources, has been the subject of investigation recently. Due to the presence of natural fractures, drilling in ultra-deep fractured tight sandstone may cause complicated wellbore instabilities, which resulted in a substantial challenge to the efficient exploitation and production of tight gas resources. In order to understand the rock mechanical properties of the ultra-deep fractured tight sandstone under shear stress, tight sandstone core samples were artificially shear-fractured, the 3D characteristics of the fractures were reconstructed by CT scanning, and the fracture aperture and roughness characteristics were systematically evaluated. Simultaneously, triaxial shear strength tests were conducted to evaluate the mechanical properties of fractured rock subjected to varying confining pressures. Considering the contact relationship of the fracture surface during shearing, two indexes of average effective shear angle and contact area ratio were proposed to correct the fracture roughness, and a new fracture shear strength model was constructed, which served as the failure criterion for the fractured formation. The results show that the intact rock has a high compressive strength and can only collapse under conditions of substantial differential stress. Consequently, shear failure of fracture ought to be the primary source of wellbore instability. The fracture aperture's spatial distribution is irregular and conforms to a Gaussian distribution. A clear anisotropy in the fracture roughness is present, and there is less roughness along the initial shear failure path and more roughness perpendicularly. With an increase in normal stress, the fracture's peak shear strength rises, while the friction angle steadily falls. The innovative model's accuracy in predicting shear strength is higher than that of the weak-surface model and the JRC-JCS model.

Reducing the Salinity of the Produced Water from Oil Field Using Activated Carbon Extracted from Waste Date Kernel

Oil production operations are commonly divided into three periods: "Primary, Secondary and Enhanced Oil Recovery EOR”. Primary recovery is considered as the initial production stage, resulting from the displacement of natural derive mechanisms that exist in a reservoir. Secondly, the secondary recovery period which is the water flooding, or gas injection. The final stage period is EOR period, which involves the injection of external material into a reservoir. Where the injected slug interacts with the reservoir rock or oil system to create favorable conditions in order to enhance the oil recovery.
 The produced water can be used as the water flooding during the secondary recovery, but the high salinity of the formations yields a low recovery factor. Thus, some materials have been used to reduce the water salinity during the production in order to reinject it into the reservoir and cause a high recovery factor. The challenge to obtain an economic material which is able to reduce the salinity in the oil fields is still at stake. Thus, many materials need to be applied in order to test its ability to reduce the water salinity. The activated carbon extracted from waste date kernel have not used yet in this area. In the present paper, the activated carbon was prepared at lab by following specific procedures. Where, a different size of activated carbon extracted from date kernel used to treat the saline water, which later will be used for a spontaneous imbibition test for sandstone core samples after saturated with crude oil. A spontaneous imbibition test consisting of three scenarios of activated carbon at various temperatures and later compared with untreated reservoir water. In this study, the spontaneous imbibition test was performed at room temperature and oven temperature including (45, 55, and 70 ℃). The results showed that activated carbon is a useful material to reduce the water salinity. Where, the best oil recovery was at a treated water with activated carbon volume (0.125), which was (70.41%), that was at the maximum used temperature.

The effects of initial water saturation on retrograde condensation in natural porous media: An in situ experimental investigation of three-phase displacements

In this study, state-of-the-art imaging technology is integrated with a miniature core-flooding system to map pore-scale fluid occupancy during the retrograde condensation process in the presence of brine and in a natural porous medium. Two depletion experiments were performed using a three-component synthetic gas condensate mixture in a Fontainebleau sandstone core sample and after establishing different levels of initial water saturations. The results are analyzed to investigate the impact of water saturation on condensate formation, accumulation, and mobilization and to shed light on the relevant three-phase flow dynamics. The results provide the first direct pore-scale observation of gas, condensate, and brine residing in the pore space. The micro-scale fluid occupancy maps illustrated that the presence of water in the pores delays the pressure at which condensate nuclei form, slows down the initial growth of nuclei, and partially impedes the accumulation of condensate. The higher the water saturation is, the lower the amount of condensate will be accumulated. As the pore pressure decreases, the condensate clusters develop significantly in the pore space triggering chains of displacement events between various pairs of fluids. The key mechanisms include gas-to-brine/condensate and condensate-to-gas/brine. The displacement events eventually reduce the brine saturation and increase the gas and condensate saturations in the pore space. The condensate saturation increases monotonically as the pore pressure reduces and reaches a maximum value. Quantitative pore fluid occupancy data also reconfirm the visual observations and demonstrate that condensate accumulation is associated with displacing gas and brine from small- and medium-sized pore elements.

Designing effective enhanced oil recovery fluid: Combination of graphene oxide, D118 SuperPusher, and Chuback surfactant

Enhanced oil recovery (EOR) is one of the most essential branches of petroleum engineering and aims to maximize oil extraction from reservoirs. This research focuses on the utilization of graphene oxide (GO) in combination with a D118 SuperPusher compound and a natural surfactant (Chuback) to enhance oil recovery. The objective is to optimize the efficiency of the EOR process through a multi-component approach. The application of Chuback leads to a substantial decrease in interfacial tension (IFT), particularly in carbonate rock formations. This is attributed to the unique characteristics of carbonate rocks, which exhibit greater susceptibility to wettability alterations. Moreover, GO nanoparticles (NPs) were synthesized, then characterized and incorporated into the surfactant-polymer system, creating surfactant-polymer-nanoparticle (SPN) fluids. The selection of optimum fluid formulations for the EOR process is facilitated through the utilization of Design Expert, a statistical software tool. Factors such as surfactant concentration, polymer concentration, NPs concentration, and two types of salt concentrations are specifically chosen as variables that can influence the fluid's performance during the flooding step. Parameters including IFT, contact angle (CA) (which affects wetting behavior), and shear viscosity (which impacts fluid flow) are considered responses. The efficacy of the suggested fluid formulation for EOR is validated through core flooding investigations. Core flooding investigations validated the efficacy of the suggested fluid for EOR, with recovery factors of up to 30% and 56% in sandstone and carbonate core samples, respectively. These findings underscore the potential of the proposed approach to significantly enhance oil recovery from both sandstone and carbonate reservoirs.

Detrital zircon and apatite U-Pb provenance and drainage evolution of the Newark Basin during progressive rifting and continental breakup along the Eastern North American Margin, USA

Abstract Mesozoic rift basins of the Eastern North American Margin (ENAM) span from Florida in the United States to the Grand Banks of Canada and formed during progressive extension prior to continental breakup and the opening of the north-central Atlantic. The syn-rift strata from all the individual basins, lumped along the entire margin into the Newark Supergroup, are dominated by fluvial conglomerate and sandstone, lacustrine siltstone, mudstone, and abundant alluvial conglomerate and sandstone lithofacies. Deposition of these syn-rift sedimentary rocks was accommodated in a series of half grabens and subsidiary full grabens situated within the Permo-Carboniferous Appalachian orogen. The Mesozoic ENAM is commonly depicted as a magma-rich continental rift margin, with magmatism (Central Atlantic magmatic province [CAMP]) driving continental breakup. However, the southern portion of the ENAM shows evidence of magmatic breakup (e.g., seaward-dipping reflectors), and rifting and crustal thinning appeared to start ~30 m.y. prior to CAMP emplacement in the Jurassic. This study provides extensive new detrital zircon and apatite U-Pb provenance data to determine the provenance and reconstruct the paleodrainages of the Newark Basin during progressive rifting and magmatic breakup and the implications for the overall rift configuration and asymmetry during progressive rifting along the ENAM rift margin. Detailed new detrital zircon (N = 21; n = 3093) and apatite (N = 4; n = 559) U-Pb results from sandstone outcrop and core samples from the Newark Basin indicate a distinct provenance shift, with relatively older Carnian syn-rift strata predominately sourced from the hanging wall of the basin bounding fault in the east while relatively younger Norian strata were regionally sourced from both the hanging wall and footwall. The syn-rift strata at the Triassic-Jurassic boundary were sourced from the hanging wall before a transition to local footwall terranes. These results suggest two major provenance changes during progressive rifting—the first occurring during Carnian crustal necking and rift flank uplift as predicted by recent numerical models and the second occurring at the onset of the Jurassic due to regional and local thermal uplift during CAMP magmatism as seen along other magma-rich margins, such as the North Atlantic and the southern portion of the South Atlantic margin.

Automatic fracture characterization in CT images of rocks using an ensemble deep learning approach

The presence of fractures in a rock mass can have a substantial influence on its mechanical and hydraulic properties. For many years, computed tomography (CT) scan has been effectively utilized to investigate the internal structures of rock. However, quantitative characterization of fracture based on CT data remains a challenging endeavor due to the inevitable blurry appearance of fractures in CT images, complexity in fracture patterns and the heterogeneity of host rock. In this study, a deep learning-based method is presented for automatically and accurately segmenting rock fractures in CT images, with special consideration for directional ambiguous fractures embedded in heterogeneous backgrounds. Our method involves two stages: (1) fracture detection in the form of minimal bounding boxes using the Faster R-CNN deep learning algorithm, and (2) fracture segmentation inside the detected bounding boxes using the U-Net deep learning algorithm. The detection stage aims to establish spatial constraints for the segmentation process, thereby significantly minimizing undesirable noise and artifacts existing in the background from consideration and consequently improving the segmentation result. In addition, we also develop a system that can automatically extract fracture properties including orientation, length, aperture, and wall roughness of fractures based on detection and segmentation results from our method. Experiments on CT images of fractured coarse-grained granite, fine-grained sandstone, and shale core samples were carried out in an attempt to confirm the applicability of our approach. The comparison between fracture segmentation results and the manually-annotated ground truths shows that our approach can achieve a competitive dice score of up to 0.942 and also outperform other state-of-the-art deep learning approaches including Mask R-CNN and U-Net alone.

Detection and visualization of micron-scale U-Ca phosphates as a key to redox and acid-base conditions in ores: sandstone-hosted uranium deposit

The presence and nature of uranium minerals subject to high leachability is one of the most significant factors in the exploitation of low-grade ores. The detection of these minerals is a challenging task due to their small size and low abundance. This paper presents a novel method of data processing that allows distinguishing and visualization of micron-scale U minerals. For this purpose, core samples of U-bearing sandstones from the Břevniště deposit (Czech Republic) were used. After their study by inductively coupled plasma spectroscopy, optical and scanning electron microscopy (SEM-EDS) and X-ray diffraction analysis, the presence of authigenic grains of U minerals occurring in various associations and their chemical compositions were confirmed by an electron microprobe. However, the use of these conventional instruments for the analysis of heterogeneous ore material with valuable information hidden, showed the necessity for a special data treatment. Matrix transformation of raw SEM-EDS data allowed for even more accurate visualizations such as contour and point maps of elemental distribution. Then, mathematical and visual correlations of transformed data revealed relationships among some measured elements (Ca, P, U, Zr, Nb, Fe, S) and their spectral overlaps. Conditions of ore formation were predicted based on the visualizations, correlations and the paragenesis of ningyoite in uranium ore. Herein suggested approach can help to identify economically significant minerals in complex mineralizations worldwide and increase the mining potential of the deposits.