Greenhouse Gases: Science and Technology最新文献

The increasing levels of carbon dioxide (CO₂) in our atmosphere demand innovative and efficient methods for its reduction. In this context, we present an advanced solar-driven photocatalyst, Pt-doped graphitic carbon nitride (Pt/g-C₃N₄), specifically engineered for enhanced photoreduction of CO₂. Our findings highlight the dual advantage of Pt/g-C₃N₄: enhanced visible light absorption and electron-hole pair dynamics, ensuring efficient carrier separation. Notably, the CO and CH₄ yields, when employing Pt/g-C₃N₄, surpassed those with the pristine g-C₃N₄ catalyst by factors of 3.1 and 4.3, respectively. Moreover, the Pt/g-C₃N₄ catalyst exhibited consistent high-efficiency of CO₂ conversion over successive cycles, emphasizing the catalyst's robustness. This work underscores the potential of Pt/g-C₃N₄ as a viable tool against escalating CO₂ levels, paving the way for a green and sustainable conversion of this predominant greenhouse gas into beneficial chemicals. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd.

We have developed a portable active seismic source (PASS) to monitor CO₂ storage reservoirs at a depth of approximately 1 km. Despite its small size, stacking the signals generated by the PASS improves the signal-to-noise ratio of the seismometer data far from the source. The smaller size and lower cost of the PASS enables its permanent deployment in many locations to continuously monitor CO₂ storage reservoirs. To achieve continuous monitoring, distributed acoustic sensing (DAS) is also a vital technology. Based on DAS, we can continuously record the signal from the PASS in an extensive area, including within boreholes and offshore fields. Here we report application of the PASS for the borehole DAS system. We confirmed the PASS signal propagation to a depth of ∼1 km when we used a PASS with 630N at 50 Hz close to the wellhead and recorded the signal by the borehole fiber optic cable. The ability of the system to propagate the PASS signal to a depth of ∼1 km enables continuous monitoring of most CO₂ storage reservoirs with high temporal resolution. Furthermore, deploying multiple PASS systems could improve the spatial resolution of monitoring results. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd.

Saline aquifer rocks exhibit significant spatial randomness due to geological sedimentation processes. To address the issue of the heterogeneity of rock formations in numerical simulations, it is common practice to homogenize rock layers with similar lithologies. However, the acceptability of the errors generated during homogenized computations is a major concern and should be investigated. Therefore, to study the influence of heterogeneity at the storage site on the CO₂ migration behavior, the Monte Carlo simulation–random finite element method (MCS-RFEM) was combined with a CO₂ two-phase flow model to compare the effects of the coefficient of variation (C_v) and correlation length (λ_x) of random reservoir permeability fields on the migration distance and extent of CO₂ storage under the same mean conditions. The results showed that higher C_v and λ_x values significantly reduced the CO₂ migration distance while increasing the spread extent. Compared to the homogeneous model, at a λ_x value of 100 m, the CO₂ migration distance decreased by 5.05%, while the profile sweep area increased by 6.20%. Concurrently, with increasing C_v, the area with a CO₂ volume fraction higher than 0.75 decreased by 20.22%, while an increase in λ_x resulted in a 42.35% increase in the area with a CO₂ volume fraction higher than 0.75. Therefore, reservoirs with high C_v and low λ_x values are more suitable for safely storing CO₂. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd.

Understanding the flow characteristics of supercritical CO₂ in dry sandstones or those with low water content provides crucial information on the flow behavior in near-wellbore zone. We conducted supercritical CO₂ core flooding experiments using sandstone cores extracted from potential CO₂ reservoirs in the Ordos Basin, China. During the experiments, we reduced the water content of saturated cores by flushing with dry CO₂ and subsequently vacuumizing them at a temperature of 35°C to simulate sandstones with low water content. The experimental results demonstrate that the CO₂ permeability was initially high during the low differential pressure stage and remained constant as the differential pressure increased. In the carbonic acid solution injection experiment, we observed an increase in the flow rate of the solution with the continuous interaction in the cores from the Shanxi and Shihezi groups, while the Yanchang group exhibited the opposite effect. This increase in permeability can be attributed to mineral dissolution and the loss of fine particles. Conversely, the blockage of fine particles or the precipitation of dissolved minerals may lead to a decrease in permeability. After the CO₂–water–rock interaction, the CO₂ permeability decreased compared to before the interaction, indicating that adsorbed water, the precipitation of dissolved mineral, or pore throat blockage by fine particles could induce this permeability decrease. The impact of adsorbed water on the decrease in CO₂ permeability is significant. Additionally, the CO₂–water–rock interaction caused corrosion on the anorthite surface. Furthermore, calcite dispersed in connected pores displayed a more pronounced dissolution compared to cemented calcite. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd.

The Intergovernmental Panel on Climate Change concludes that CO₂ capture and storage (CCS) is critical for climate-stabilizing energy transitions. In CCS, captured CO₂ is sequestered in saline aquifers within sedimentary basins. The CO₂ storage capacity and the rate of injection are functions of the geology of the saline aquifer, which is uncertain. To minimize impacts of this uncertainty, CCS projects could include backup plans, such as co-locating geologic CO₂ storage (GCS) sites with or near existing CO₂-enhanced oil recovery (CO₂-EOR) operations. These “stacked storage” projects could hedge against uncertainty in the saline formation performance because captured CO₂ could be injected into either location in the event of unexpected events (e.g., the injectivity decreases). Here, we investigate the possibility and ramifications of developing CCS networks in Oklahoma that are amendable to stacked storage. We find that stacked storage is possible in Oklahoma but the counties with the lowest-cost saline storage resources do not have existing CO₂-EOR operations. At the systems level, we find it is slightly more expensive (e.g., $1/tCO₂ to $5/tCO₂) to site GCS in counties with CO₂-EOR projects. This increased expense is largely due to increased CO₂ transportation costs because hundreds of km of additional pipeline is required to capture CO₂ from the lowest-cost sources. Overall, our results suggest that it is optimal to build more pipelines and avoid injecting CO₂ in some of the lowest-cost saline storage resources, to enable capturing CO₂ from the least-cost sources. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd.

In light of the current situation where the utilization of calcium carbide slag yields low profits but holds significant potential for reducing carbon emissions, ammonium acetate was employed to leach calcium carbide slag. It also played a crucial role in regulating the products of indirect carbon dioxide carbonation when mixed with glycine and lye. Ammonium acetate's significance underscores its dual role in both the leaching and carbonation processes. This process yielded calcium carbonate with particle sizes smaller than 100 nm, with a purity of 98% and a single vaterite phase. The calcium carbide residue demonstrated an impressive CO₂ uptake rate of 23.5%. Ammonium acetate exhibited an efficiency of 79.2% as a leaching agent. The ammonium acetate method demonstrated enhanced environmental friendliness and facilitated a more efficient carbon uptake rate of 23.5% compared to conventional indirect methods. Furthermore, the addition of lye, glycine, and ammonium acetate effectively extended the nucleation time of the calcium carbonate crystals and induced the formation of more vaterite intermediates with smaller particle sizes. The influence mechanism of compound additives on the carbonation reaction was revealed through kinetic analysis and molecular dynamics. This innovative approach offers a promising avenue for simultaneously treating solid waste and reducing CO₂ emission. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd.

The generation of heat-stable salts (HSSs) in alkanolamine solutions for CO₂ capture processes, which is adapted for power plant technologies, exists irrespective of the class of amine solution used for the capture process. Their presence do not only trigger decrements in the CO₂ absorption capacities of the solvents and contribute to further alkanolamine degradation, but also result in foaming and loss of solvents, which impacts system economics and threatens the environment. HSSs also promote the corrosiveness of the metallic structures of capture systems by lowering the pH and increasing the conductivity of the absorbent solutions. Overall, these effects substantially subvert the reliability and integrity of CO₂ capture units. This survey affords sufficient background on the existence of HSSs by unraveling the flow process in a typical alkanolamine-based CO₂ capture unit with respect to their formation points and potential threats. Furthermore, the major HSSs removal and alkanolamine reclamation methodologies (electrodialysis, distillation, ion exchange, electromagnetic separation, and solvent extraction) were comprehensively explored. We believe that this review paper will benefit researchers across disciplines as we continue to explore new and complex solvent formulations to minimize the cost of CO₂ capture while maximizing efficiency. © 2023 Society of Chemical Industry and John Wiley & Sons, Ltd.

Shales have low to ultra-low porosity and permeability, which makes them an attractive candidate for CO₂ utilization during CO₂-enhanced oil recovery (CO₂-EOR) or for geologic CO₂ storage (GCS). Shale are source rocks, and thus, there is a continuous induced diagenetic process that can alter their properties as they reaches maturity at greater in situ temperature. However, there are significant knowledge gaps in the possibility of CO₂ utilization during this diagenetic process (thermal maturation) to achieve long-term CO₂ storage. This experimental study investigates the potential for CO₂ utilization in shale due to induced thermal maturation at in situ conditions, and the implications of pre-maturation CO₂ injection in shale for GCS and CO₂-EOR. Here, we used subsurface hydrocarbon-rich Bakken and Green River shales exposed to CO₂ for a specific period. This is followed by inducing the unexposed and CO₂-exposed shales to thermal maturity. Subsequently, we evaluated the total organic carbon (TOC), liberated hydrocarbons (S₂), and the mineralogical and mechanical properties of the mature and CO₂-exposed mature shales. We further assessed the implications of CO₂ utilization and storage in thermally matured Bakken and Green River shales for long-term storage or CO₂-EOR. The results indicate that if CO₂ is injected into shales before attaining maturity, higher hydrocarbon production and more significant mechanical weakness can be expected when they attain maturity in Bakken shales (+30% liberated hydrocarbons; −31% Young's modulus; −34% hardness) and Green Rivers shales (+8% liberated hydrocarbons; −40% Young's modulus; −30% hardness), and this is relative to Bakken and Green River shales without CO₂ injection before attaining thermal maturity. Further, CO₂-exposed mature Bakken and Green River shales can alter the minerals in shales with the dissolution of dolomite and precipitation of calcite, which promotes mineral trapping and achieve a lower TOC (Bakken shale = −24%; Green River shale = −26%), and this is relative to Bakken and Green River shales without CO₂ injection before attaining maturity. Analyses of the results suggest that the application of this proposed CO₂ injection and utilization in immature shales could access more excellent CO₂-storage reservoirs in Bakken and Green River shales without waiting for a more extended period for the shales to become viable and mature, which is the case with the present GCS and CO₂-EOR operations in shale reservoirs globally. Also, our proposed pre-maturation CO₂ injection could rejuvenate mature shales for increased hydrocarbon production through CO₂-EOR, yield a greater sealing efficiency, and mitigate leakage risks for long-term C