Salt precipitation has emerged as a critical factor affecting injectivity, reservoir stability, and the potential to trigger near-wellbore microseismic activity during geological CO2 sequestration. While previous studies have primarily focused on the brine acidification induced by CO2 injection, triggering geochemical reactions in carbonate rocks and leading to mechanical degradation, the mechanical behavior associated with salt precipitation in drying zones, particularly the failure mechanisms, remains poorly understood. In this work, we designed a reservoir-condition displacement system to mimic near-wellbore drying process and further investigated the rock failure modes due to salt precipitation in red sandstone samples. Our study demonstrates that, despite the densification of the pore structure due to salt precipitation, the overall mechanical performance of the rock undergoes significant deterioration. More importantly, for the first time, we observe a distinct transition of failure mode from shear-to tensile-dominated under uniaxial compression. Microstructural analysis further shows that the growth of polycrystalline and bulk crystals induces microcrack initiation and propagation, with the failure mechanism of rocks subjected to salt precipitation primarily characterized by intercrystalline damage at weak bonding interfaces under external loading.

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Geological sequestration of CO2 has emerged as a promising and viable strategy to mitigate climate change by injecting supercritical CO2 (scCO2) into deep subsurface formations for long-term containment. This process can induce salt precipitation, a phenomenon where dissolved salts crystallize out of pore brine. Such precipitation poses significant challenges, including pore blockage, reduced rock strength, and a potential contribution to microseismicity that may compromise reservoir stability. In this study, the effects of salt precipitation on the microstructure and failure characteristics of reservoir rocks were experimentally investigated under reservoir-representative conditions. Results indicate that while salt crystallization densifies the rock's pore structure, it paradoxically undermines the overall mechanical integrity. Specifically, the load-bearing capacity is significantly reduced, making the rock increasingly prone to tensile failure as opposed to shear failure under compressive stress. Given that fluid injection most commonly induces shear failure, particularly in the presence of pre-existing faults, a shift toward tensile-dominated failure makes reservoir damage more complex. Moreover, tensile failure promotes fracture opening and propagation, thereby increasing uncertainty in CO2 migration prediction and monitoring. This transition in failure mode is attributed to weak interfacial bonding between the salt crystals and the rock matrix, along with an increased development of microcracks. These findings provide critical insights into the stability of geological reservoirs during CO2 sequestration and establish a scientific basis for investigating the mechanisms of injection-induced microseismicity.

Halite precipitation during CO2 injection can significantly reduce injectivity and impact long-term storage in saline aquifers and depleted reservoirs. However, the impact of geological porous media on salt precipitation and brine movement is not fully undersood. This study explores salt precipitation dynamics from the pore to core scale using microfluidic experiments and core-flooding tests. Microfluidic results reveal three distinct phases of salt deposition: slow evaporation, rapid evaporation, and complete dry-out. Heterogeneous pore structures retain more initial water, leading to localized salt accumulation due to capillary effects. Core-scale experiments show that permeability strongly influences salt penetration and porosity reduction. In high-permeability cores, salt fronts extend deeper into the rock, causing up to 70% porosity reduction. In contrast, heterogeneous cores experience limited salt penetration but increased surface accumulation, suggesting that capillary pressure and brine redistribution control final deposition patterns. These findings highlight the complex interactions between fluid flow, rock properties, and salt crystallization, which provides valuable insights for predicting injectivity loss and optimizing CO2 storage strategies. Understanding these mechanisms is essential for improving reservoir management and ensuring the long-term stability of geological CO2 sequestration projects.

Hypothesis: Interface dynamics, such as Haines jumps, are crucial in multi-phase flow through porous media. However, the role of intrinsic surface wettability in pore-filling events remains unclear, and the pressure response requires further study. This work evaluates the impact of wettability on interface stability and pressure dynamics. Experiments and simulations: We performed microfluidic experiments and level-set simulations of two-phase flow. Water displaced air or Fluorinert in a PDMS micro-model with controlled wettability (contact angles: 60^∘, 95^∘, 120^∘). Three injection velocities covered capillary- to viscous-dominated flow regimes. High-resolution imaging and synchronized pressure recordings linked interface curvature with capillary pressure changes. Findings: At low capillary numbers, wettability strongly affects burst pressure and pinning. Its influence decreases at higher capillary numbers. We observed an apparent wettability shift due to hysteresis and a capillary pressure barrier linked to pore-wall slope variations. Simulations replicated experimental trends, confirming the role of wettability in pore-scale displacement. These findings provide critical insights for improving pore-network models and understanding wettability effects in porous media.

Carbon dioxide capture and storage in subsurface geological formations is a potential solution to limit anthropogenic CO₂ emissions and combat global warming. Depleted gas fields offer significant CO₂ storage volumes; however, injection of CO₂ into these reservoirs poses some potential challenges for the injectivity, containment and well/facility integrity due to low temperatures caused by isenthalpic expansion of CO₂. A key injectivity risk is due to possible formation of hydrates at the low expected temperatures. This study aims to address main causes of CO₂ hydrate formation and its impact on permeability of porous media. This review highlights the current state of knowledge in the literature while emphasizing the need to bridge existing gaps in derisking CO₂ injection into (depleted) low-pressure gas reservoirs. In summary, according to the existing literature, the potential for hydrate formation is assessed to be credible. Current industry solutions exist to manage this risk; however, they are costly and energy intensive. Future research will be needed to provide capabilities to manage this risk more efficiently.

With the intensification of global climate change and the growing demand for the Sustainable Development Goals (SDGs), dual-carbon policies are on the rise globally, bringing new challenges and opportunities to the energy industry. Focusing on the photovoltaic (PV) industry, this study carries out a carbon footprint analysis in the context of dual-carbon to gain a comprehensive understanding of the current status of PV modules in terms of carbon emissions and emission reduction measures. This paper firstly summarizes the development of the PV industry, and deeply analyzes the relevant theories and methods of carbon footprint assessment and accounting system. Then, it systematically evaluates the carbon emissions of crystalline silicon PV modules throughout their life cycle, and based on this, it puts forward suggestions on strategies to reduce the carbon footprint. Finally, the opportunities and challenges that the PV industry may encounter in the process of moving towards a low-carbon future are discussed to provide a reference for decision-making and practice in this field.

CO2 storage in deep saline aquifers is an effective strategy for reducing greenhouse gas emission. However, salt precipitation triggered by evaporation of water into injected dry CO2 causes injectivity reduction. Predicting the distribution of precipitated salts and their impact on near-well permeability remains challenging. Therefore, a detailed investigation of the interactions between salt precipitation and porous domain is essential for of revealing the mechanisms of pore blockage due to salt crystallization. Through series of microfluidic experiments, direct observations, coupled with detailed imaging processing, form the basis for explaining these phenomena and provide a relationship between water and salt saturations, highlighting the critical roles played by local capillary-driven flow and water film along grains in influencing water relocation. The results reveal two distinct types of salt crystallization: occurring inside the brine with smooth edges and at the CO2-brine interface with rough edges. Furthermore, the impact of local heterogeneity and surface wettability on salt precipitation patterns is discussed. The transition region between the porous domains and inlet/outlet channels exhibits brine backflow and a larger amount of salt accumulation. This paper presents a comprehensive analysis of the dynamic process of salt dry-out occurring during CO2 injection at the pore scale.

Low salinity water flooding is a common technique for enhancing oil recovery; however, the mechanism behind the low-salinity effect, positive or negative, is still not fully understood. In the proposed mechanisms, osmosis and emulsification are considered as two potential reasons for explaining the oil remobilization, but the specific contributions on the remobilization are not well studied at pore-scale. In this article, we performed a series of microfluidic experiments to investigate the movement of constrained oil between invading low-salinity brine and residual high-salinity brine. We find that various salinity contrasts over oil films cause different water fluxes through the oil and swelling areas of the trapped brine, resulting in the relocation of oil phases within the pore spaces. A higher salinity contrast (1.7-170 g/L salt concentrations) provides a faster water penetration in oil phases. In the presence of an oil-soluble surfactant, spontaneous emulsification occurs at the interface of low-salinity brine/oil, which enhances almost 100 times the water flux in two oil phases (n-heptane and n-dodecane). We directly observe pore-scale spontaneous emulsification at the low-salinity brine/oil interface but not at the high-salinity brine/oil interface. Furthermore, two scenarios for explaining water transport through the oil phase are proposed: water diffusion due to chemical potential gradient and water transport via reverse micelle or microemulsions movement.

Understanding the kinetics of CO2 hydrate formation and the resulting saturation of the hydrate in porous rocks is crucial for processes such as the storage of CO2 in underground formations. Nevertheless, to date, there is no established procedure that utilizes a medical CT scanner for quantifying gas hydrate saturation in core samples during the growth stage. This study proposes a methodology for estimating hydrate saturation using a medical CT scanner during the injection of CO2 into porous media. This method uses the mean area obtained from the image analysis to calculate the dynamic profile of water and the CO2 hydrate along the length of the sandstone core. To demonstrate the technique, core flooding experiments were conducted to form gas hydrates in semibrine-saturated sandstone cores.