The global demand for critical minerals and materials (CMM) is rapidly outpacing conventional supply chains. Traditionally, CMM extraction and hydrocarbon production have operated as segregated industries, with the former often requiring energy-intensive mining of greenfield sites. This Perspective presents a paradigm shift by demonstrating that mature U.S. sedimentary basins are not merely depleting fuel reservoirs but are vast, accessible repositories of mineral wealth. By integrating in-situ mining (ISM) chemistries into existing oil and gas infrastructure, we can leverage billions of dollars in sunk capital to address modern supply chain bottlenecks while simultaneously enhancing energy recovery. Our analysis of thirteen major unconventional U.S. hydrocarbon reservoirs identifies a robust endowment of fifteen critical elements, including titanium, vanadium, nickel, cobalt, etc., ubiquitous within the sedimentary matrix. We highlight that 1% enhanced recovery rate of hydrocarbon from the existing reservoirs and 1% recovery rate of CMM from 5% of these accessible formation volumes could yield over 5 billion barrels of oil, 60 Tcf natural gas, and 500 million metric tons of CMM, contextually sufficient to revolutionize energy landscapes and advanced manufacturing. Future research must focus on optimizing selective lixiviants that maintain reservoir integrity while maximizing yields of CMM and hydrocarbons within a closed-loop system. Redefining the subsurface as an integrated factory (earth as a reactor) offers a pragmatic and low-footprint pathway to secure national industrial competitiveness and advance technological leadership.

Carbon sequestration is one approach to achieve carbon dioxide reduction in the atmosphere. Underground storage of CO2 requires an understanding of geochemical and geomechanical alteration on the integrity of the injection wellbore. In this study, we investigate the reactivity of supercritical CO2 (scCO(2)) at 65 degrees C and 20.7 MPa on Portland class G cement plugs used for oil and gas well completion, for exposure of up to 5 weeks. For nanoporous media, such as cement, diffusion is believed to be the major mass transport mechanism (Perkins and Johnston, 1963) [1]. To quantify the extent of the alteration (mineralization/dissolution) on fluid diffusivity through the cement matrix, a novel approach based on Nuclear Magnetic Resonance (NMR) is employed to derive diffusional tortuosity. Comparing pre- and post-scCO(2) exposure, deuterium oxide (D2O) intrusion profiles allow us to determine flow path alteration in the cement plugs. Additional characterizations include Fourier Transform Infrared Spectroscopy (FTIR) to observe the change in cement composition, micro X-ray Computed Tomography (mu XCT), along with Scanning Electron Microscopy (SEM) and Energy Dispersive Spectroscopy (EDS) to determine invasion extent and microstructure modifications, Mercury Injection Capillary Pressure (MICP) for pore throat size distribution and BET N-2 isothermal adsorption for surface area and pore size distribution. The results show that exposure to scCO(2) promotes both calcium carbonate precipitation and dissolution simultaneously. However, the alteration is pore size dependent. After 5 weeks of exposure, there is evidence of carbonate dissolution in smaller pores (<30 nm) and both precipitation and dissolution in larger pores (30-200 nm). The alteration of the cement plugs leads to a decrease in the storage and connectivity of the cement. The porosity decreased from 37 to 33 % in 5 weeks, while the matrix tortuosity increased by 6 and 3 times after 2 and 5 weeks of exposure, respectively. The experimental results imply that the cement carbonate precipitation can limit the migration of scCO(2) through the cement matrix. This work also highlights an alternative laboratory approach to quantify the risk associated with scCO(2) exposure on Portland cement using NMR-derived tortuosity

Summary Supercritical carbon dioxide (scCO2) trapping mechanisms within carbon geostorage (CGS) primarily hinge on the upper caprock system, with shales being favored for their fine-grained nature and geological abundance. Experimental assessments of CO2 reactivity in brine-saturated shales reveal microstructural changes, raising concerns about long-term CO2 leakage risks. Existing models of scCO2 transport through caprocks lack consideration for shale anisotropy. This study addresses these gaps by investigating the diffusive properties and propagation of geochemical reactivity in shaly caprocks, accounting for anisotropy. Horizontal and vertical core samples from three shale formations with varying petrophysical characteristics underwent mineralogical, total organic carbon (TOC), porosity, and velocity measurements. scCO2 treatment for up to 3 weeks at 150°F and 3,000 psi was conducted. The propagation of geochemical reactivity was monitored by multiple surface X-ray fluorescence (XRF) measurements and fine polishing. A nuclear magnetic resonance (NMR)-based H2O-D2O fluid exchange protocol was used to quantify effective diffusivities and tortuosities parallel and perpendicular to bedding. Results indicate preferential surface reactivity toward carbonate minerals; however, the apparent reaction diffusivity of the shaly caprock is notably slow (~10−15 m2/s). This aligns with previous experimental and reactive transport modeling studies, emphasizing long timescales for carbonate dissolution reactions to influence shale caprock properties. Shale-effective diffusivities display anisotropy increasing with clay content, where diffusivities parallel to bedding exceed those perpendicular by at least three times. Faster horizontal diffusion in shaly confining zones should be considered when estimating diffusive leakage along faults penetrating these zones, a significant risk in CGS. Post-scCO2 treatment, diffusivity changes vary among samples, increasing within the same order of magnitude in the clay-rich sample. Nonsteady-state modeling of scCO2 diffusion suggests limited caprock penetration over 100 years, with a minimal increase from 5 m to 7 m post-scCO2 treatment for the clay-rich sample. This study extends existing literature observations on the slow molecular diffusion of scCO2 within shaly caprocks, integrating the roles of geochemical reactions and shale anisotropy under the examined conditions.

The displacement efficiency of supercritical CO2 (scCO2) injection in the storage zone and its primary trapping mechanism in the confining zone are strongly tied to the capillary phenomenon. Previous studies have indicated that the capillary phenomenon can be affected by geochemical reactivity induced by scCO2 dissolution in formation brine. To quantify such changes, thin disk samples representing a sandstone storage reservoir, siltstone confining zone, and mudstone confining zone were treated under a scCO2-enriched brine static condition for 21 days at 65 °C and 20.7 MPa. Geochemical alterations were assessed at the surface level using scanning electron microscopy coupled with energy-dispersive X-ray spectroscopy and X-ray fluorescence. Before and after treatment, the wettability of the scCO2–brine–rock systems was determined using the captive-bubble method at fluid-equilibrated conditions. Pore size distributions of the bulk rocks were obtained with mercury injection capillary pressure, nuclear magnetic resonance, and isothermal nitrogen adsorption. The results indicate the dissolution of calcite at the surface, while other potentially reactive minerals (e.g., clays, feldspars, and dolomite) remain preserved. Despite alteration of the surface mineralogy, the measured contact angles in the scCO2–brine–rocks systems do not change significantly. Contact angle values of 42 ± 2° for sandstone and 36 ± 2° for clay-rich siltstone/calcite-rich mudstone were determined before and after treatment. The rocks studied here maintained their water-wettability at elevated conditions and after geochemical reactivity. It is also observed that surface alteration by geochemical effects did not impact the pore size distributions or porosities of the thin disk samples after treatment. These results provide insights into understanding the impact of short-term geochemical reactions on the scCO2–brine capillary displacement in the storage zone and the risks associated with scCO2 breakthrough in confining zones.

The development of unconventional resources in the Uinta basin requires more investigation. Petrophysical characterization is the key to identifying different rock types to optimize hydrocarbon production. Rock-typing can be performed using wireline measurements, such as triple combo and special logs; however, this identification needs to be verified using laboratory characterization to enhance the accuracy of rock-typing prediction models. In this work, we implement an integrated characterization workflow for 600 ft of the core interval, including total organic carbon, source rock analysis, elemental (X-ray Fluorescence) and mineral (Fourier- transform Infrared Spectroscopy) composition, total porosity (High-pressure pycnometer, Nuclear Magnetic Resonance), pore throat size distribution (Mercury Injection Capillary Pressure), elastic moduli (Ultrasonic velocity and nanoindentation) and microstructure (Scanning Electron Microscopy). Wireline measurements include the triple combo and the sonic logs. Principal Component Analysis and K-means (as unsupervised machine learning algorithms) were applied to both datasets to cluster and classify different rock types. In parallel, the petrophysical systematic for each rock type was evaluated. The Uinta group is vastly diverse, having a wide range of porosity (2-18%) and TOC (0.5-10%). Three main rock types were identified type 1-siliceous rich, type 2-calcite rich, and type 3-dolomite rich. The relative contribution of types 1, 2, and 3 is 47, 31, and 22 %, respectively. The top section of the analyzed core is dominated by rock type 1, which generally has the highest porosity and relatively higher TOC. Most of the bottom section is carbonate-rich rock types, in which calcite-rich and dolomite-rich layers are interbedded; SEM analyses suggest that a fraction of the porosity is associated with organic matter. Between rock types 3 and 2, further studies indicate that the high dolomite rock type tends to have higher porosity, larger pore size, and better-sorted grains, while the high calcite rock type has lower porosity and small pore size. There is a fair agreement in rock type identification between using core-derived and log- derived models. The Uinta basin leads the hydrocarbon production in Utah. The study provides a comprehensive core analysis dataset highlighting the vertical complexity of the Uinta group. The agreement in rock-typing using core and wireline inputs suggests that log-derived rock-typing can be utilized to identify sweet zones.

Experimental adhesives containing co-doped metaloxide nanoparticles were demonstrated to display strong and long-term antibacterial properties against Streptococcus mutans biofilms. The present study represents an effort to characterize the shear-bond strength (SBS) and color stability (CS) of these novel biomaterials. Experimental adhesives were obtained by dispersing nitrogen and fluorine co-doped titanium dioxide nanoparticles (NF_TiO2, 10%, 20% or 30%, v/v%) into OptiBond Solo Plus (OPTB). Dentin surfaces were wet-polished (600-Grit). Specimens (n = 5/group) of Tetric EvoCeram were fabricated and bonded using either OPTB or experimental (OPTB + NF_TiO2) adhesives. Specimens were stored in water (37 °C) for twenty-four hours (T1), three months (T2), and six months (T3). At T1, T2, or T3, specimens were removed from water storage and were tested for SBS. Disc-shaped specimens (n = 10/group; d = 6.0 mm, t = 0.5 mm) of adhesives investigated were fabricated and subjected to thermocycling (10,000 cycles, 5–55 °C, 15 s dwell time). Specimens’ colors were determined with a VITA Easyshade® V spectrophotometer (after every 1000 cycles). SBS data was analyzed using two-way ANOVA and post-hoc Tukey tests, while CS data was analyzed using one-way ANOVA and post-hoc Tukey tests (α = 0.05). Mean values of SBS ranged from 16.39 ± 4.20 MPa (OPTB + 30%NF_TiO2) to 19.11 ± 1.11 MPa (OPTB), from 12.99 ± 2.53 MPa (OPTB + 30% NF_TiO2) to 14.87 ± 2.02 (OPTB) and from 11.37 ± 1.89 (OPTB + 20% NF_TiO2) to 14.19 ± 2.24 (OPTB) after twenty-four hours, three months, and six months of water storage, respectively. Experimental materials had SBS values that were comparable (p > 0.05) to those from OPTB independently of nanoparticle concentration or time-point considered. Experimental materials with higher NF_TiO2 concentrations had less intense color variations and were more color stable than OPTB even after 10,000 thermocycles. In combination, the results reported have demonstrated that experimental adhesives can establish strong and durable bonds to human dentin while displaying colors that are more stable, thereby suggesting that the antibacterial nanotechnology investigated can withstand the harsh conditions within the oral cavity without compromising the esthetic component of dental restorations.

Recent interest in EOR in unconventionals, typically comprised of organic and inorganics, begs the question: does the process change the rock in measurable ways? We ran a series of EOR huff-n-puff experiments to assess hydrocarbon recoveries. We varied soak times, injection pressures and number of cycles, measured what was produced, and looked at the microstructure before and after the EOR huff-n-puff process. We have documented significant changes in the pore structure, in particular, in the organic component, which leads to increased porosity and connectivity and non-monotonic cyclic recovery efficiencies.

This study reports the application of a deep learning workflow using convolutional neural networks (CNN) to classify scanning electron microscopy (SEM) microstructural images of different shales to determine geologic formation based only on the SEM image. We used approximately 27,000 SEM images (512 x 512 pixels) from 18 different unconventional reservoir formations with a range of maturities to train a CNN through transfer learning. Our test results show a 93% accuracy in identifying the correct formation using SEM images. In addition, we also generated the probabilities of an image associating, or being similar to, different formations. These probabilities allow the user to determine what formations or zones of a formation have similar micro-structures. The most important aspect of the workflow is the extremely rapid classification. After fully training the network for 120 h, we were able to predict the formation and the associated probabilities with different formations in 1.8 ms/image.

固体沥青会显著影响许多致密储层的品质.不列颠哥伦比亚省东北部和艾伯塔省西北部以粉砂岩为主的Montney组中有机质组分主要为固体沥青,代表了一种充注原始孔隙但后来被热裂解的油相.本研究认为,通过应用原始孔隙度和沥青饱和度概念,可进一步理解固体沥青对储层品质的影响.原始孔隙度是指现今孔隙度与总有机碳(TOC)体积分数的总和,在概念上定义为充油时可用的孔隙度.沥青饱和度是TOC体积除以原始孔隙度,在概念上定义为充满油或沥青的原始孔隙度所占比例.本文介绍了原始孔隙度-沥青饱和度相关图,并将其与有机岩相学和扫描电子显微镜观察相结合,以研究原始孔隙度和沥青饱和度的不同组合如何影响岩石性质.Montney组中的固体沥青会影响孔喉尺寸、孔隙度、渗透率以及润湿性.通过将原始孔隙度和沥青饱和度认定为具有广泛组合的固有岩石属性,可了解这些关键的岩石性质.本研究提出的原始孔隙度和沥青饱和度概念可应用于其它有机质以固体沥青为主的致密油气储层中.

Volcanic ash beds are thin layers commonly observed in the Eagle Ford, Niobrara and, Vaca Muerta formations. Because of their differences in composition, sedimentary structures, and diagenetic alteration, they exhibit a significant contrast in mechanical properties with respect to surrounding formation layers. This can impact hydraulic fracturing, affecting fracture propagation and fracture geometry. Quantifying the mechanical properties of ash beds becomes significant; however, it is a challenge with traditional testing methods. Common logging fails to identify the ash beds, and core plug testing is not possible because of their friability. In this study, nanoindentation was used to measure the mechanical properties (Young's modulus, creep, and anisotropy) in Eagle Ford ash beds, and to determine the contrast with the formation matrix properties. Two separate ash beds of high clay and plagioclase composition were epoxied in an aluminum tray and left for 48 hours curing time. Horizontal and vertical samples of ash beds were acquired and mounted on a metal stub, followed by polishing and broad beam ion milling. Adjacent samples were also prepared for high-resolution Scanning Electron Microscope (SEM) microstructural analysis. The Young's modulus in ash beds ranged from 12 to 24 GPa, with the horizontal direction Young's modulus being slightly greater than that of the vertical samples. The Young's modulus contrast with adjacent layers was calculated to be 1:2 with clay-rich zones and 1:4 with calcite rich zones. The creep deformation rate was three times higher for ash beds compared to other zones. Using Backus averaging, it was determined that the presence of ash beds can increase the anisotropy in the formation by 15-25%. SEM results showed a variation in microstructure between the ash beds with evidence of diagenetic conversion of rhyolitic material into clays. Key differences between the two ash beds were due to the presence of plagioclase and the occurrence of porosity within kaolinite. Overall porosity varied between the two ash beds and adjacent carbonate layers showing a significant increase in porosity. Understanding the moduli contrast between adjacent layers can improve the hydraulic fracturing design when ash beds are encountered. In addition, the presence of these beds can lead to proppant embedment and loss in fracture connectivity. These results can be used for improving geomechanical models.

The nature and distribution of native fluids, both hydrocarbons and water, exert fundamental control on the petrophysical properties and fluid dynamics of unconventional, low-permeability reservoir rocks. Here, we report dynamic native fluid phenomena that occurred serendipitously during scanning electron microscopy (SEM) imaging of petroliferous siltstones from the Triassic Montney Formation of western Canada. These observations of fluid movement provide rare in-situ contextual information about the nm-to um-scale distribution of fluids in tight unconventional reservoirs. Dynamic oil behaviour is indicated by expulsion structures that formed in pore-filling solid bitumen when trapped oil erupted from the sample while under vacuum pressure conditions. These structures strikingly show that oil and solid bitumen intimately coexist within the pore network of tight rocks in the oil reservoir-fluid window. Dynamic brine behaviour is evident from strings of halite crystals overlying pores between minerals. The halite crystals precipitated from hypersaline brine that migrated from the interior to the surface of the sample. This behaviour indicates well-connected brine exists in Montney siltstone pores, even those substantially filled with hydrophobic solid bitumen. These SEM observations support previous petmphysical studies that suggest the electrical conductivity of Montney rocks is controlled primarily by their bulk volume of well-connected hypersaline water.