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• Sandstone from Khorat Plateau of Thailand was examined its CO 2 storage capacity. • CO 2 -rock geochemistry and fluid flow were examined for residually trapped CO 2. • Rock mineral dissolution and precipitation occurred, with intervention of fines migration. • Storage capacity of 9.66 kg/m3 was estimated, with a slight geochemistry influence. • Considerably altered permeability could agitate CO 2 injectivity and plume behavior. To achieve a gigaton-scale CO 2 geological storage, several sedimentary formations are widely assessed for their potential for dedicated storage projects. As one of the large formations in Southeast Asia, the Khorat Plateau in Thailand is of significant interest. While previous studies have reported discrepancies in the capacity estimate, effective capacity considering experimental examination is needed to properly elucidate project development in the area. In the current study, geochemistry and CO 2 -brine flow were experimentally examined using samples of Khorat sandstone. Owing to CO 2 geochemical reactions coupling with flow-induced fines migration, dissolution-precipitation of the sample minerals at sub-core scales were intricate and led to changes in core-scale properties as a result. After the samples were exposed to CO 2 -saturated brine, quartz likely dissolved while calcite precipitated. At the core scale, permeability declined due to residual clay blockage. On the contrary, after supercritical CO 2 exposure, the minerals were severely dissolved, which led to the expansion of pore networks and increases in porosity and permeability. Relative permeabilities of CO 2 and brine were characterized, and the residually trapped amount of CO 2 was obtained (26% of pore volume). The storage capacity was calculated to be 9.66 kg/m3, which was found to be relatively less influenced by the geochemistry-induced physical alterations. [Display omitted] [ABSTRACT FROM AUTHOR]

• Presentation of the Helguvik pilot project for in-situ CO 2 mineral storage with saline water. • Crosshole seismic and electrical resistivity tomography delineate zones of high and low porosity in the subsurface, highlighting potential pathways for the injected, CO 2 -saturated waters. • Detailed subsurface model of the Helguvik site as a baseline for time-lapse measurements to quantify and locate carbonate precipitation. In-situ CO 2 mineral storage is moving into focus as a technology for storing substantial amounts of CO 2 that would otherwise be released into the atmosphere. However, one of the main drawbacks of this technology is that it requires large amounts of freshwater for injection. To overcome this obstacle, a pilot project in Helguvik, Iceland is testing the effectiveness of carbon mineralization using saline water, similar to seawater. Here, we describe the project and the geophysical characterization of the pilot site using crosshole seismic- and single-hole electrical resistivity measurements. The data show that the subsurface strata are dominated by decameter-thick horizontal layers of basaltic strata, with varying seismic velocities and electrical resistivities. Variations in both seismic velocity and electrical resistivity are in excellent agreement and delineate high and low porosity zones in the subsurface. The results are compared to well logging results and the mineralogical composition of drill cuttings to build a comprehensive subsurface model of the future CO 2 mineral storage reservoir, highlighting potential pathways for the injected CO 2 -charged waters. [ABSTRACT FROM AUTHOR]

• Micro-CT imaging improves micro-scale heterogeneity capture in reservoir modelling. • Otway Formation case study shows digital core analysis enhances CO 2 sequestration characterization. • Digital core analysis reduces uncertainty, enhancing accuracy of reservoir property measurements. • Digital techniques and upscaling improve large-scale reservoir simulation precision. Conventional reservoir models of heterogeneous reservoirs do not include micro-scale heterogeneity due to the resolution limitations of widely used well logs and core plug data. This leads to a lack of precision in the characterization of the reservoir. The reservoir quality of the thin sandstone layers in heterogeneous reservoir are critical factors for CO 2 sequestration. The integration of micro-CT images from rock samples and upscaling algorithms, enables a comprehensive understanding of reservoir properties and facilitates accurate reservoir modelling. This research aims to enhance reservoir characterization and modelling by upscaling digital core data from micro scale to field scale. By focusing on the Otway Formation as a case study, this paper demonstrated the potential of digital core analysis in improving reservoir characterization and provided valuable insights for efficient CO 2 sequestration. The findings of this study have significant implications for the oil and gas industry, promising to enhance reservoir characterisation and modelling for CO 2 sequestration projects. [ABSTRACT FROM AUTHOR]

• Batch dissolution test using CO 2 at various concentrations is an efficient and accurate method to quantify reactivity (i.e., labile cations) for carbon mineralization. • Labile Mg content of serpentine group minerals is determined by serpentine polymorphs and reactive surface area. • Labile Mg content in hydrotalcite group minerals is determined by the nature of the divalent and trivalent cations within the mineral structure. • Mineral type, abundance and surface area are fundamental controls of labile Mg in ultramafic rocks and tailings. The growing demand for effective carbon mineralization technologies to combat climate change necessitates precise reactivity characterization of feedstocks. In this study, we introduced and validated a batch dissolution experimental protocol for efficient quantification of labile Mg, an indicator of carbon mineralization reactivity derived from ultramafic rocks, minerals, and tailings. This method is used to characterize labile Mg content in various ultramafic minerals, including serpentine and hydrotalcite group minerals, as well as rocks like serpentinite, dunite, harzburgite, and tailings. Antigorite exhibits the lowest labile Mg content within the serpentine mineral group, whereas chrysotile releases the most. Differences in labile Mg content within the hydrotalcite group depend on the trivalent cation species, with Fe3+-rich pyroaurite and iowaite demonstrating higher labile Mg content than Cr3+, Al3+-rich stichtite and hydrotalcite. We found that grain size impacts the reactive surface area of ultramafic rocks and tailings, while protolith composition and rock alteration stages affect mineralogy. Consequently, under consistent geochemical conditions, we identified mineral type, abundance and reactive surface area as primary controls of labile Mg content. Principal Component Analysis (PCA) further validated our findings, showing that mineralogy and reactive surface area could account for over 90 % of the variability in labile Mg measurements. Predicting labile Mg content based on these variables yielded results comparable to experimental outcomes, providing insights into carbon mineralization reactivity and demonstrating methods for accurate evaluation. [ABSTRACT FROM AUTHOR]

• Dry-out in a storage formation induces capillary-driven backflow from confining formations. • Dry-out in the storage formation causes CO 2 invasion into confining formations. • The above invasion occurs even when pressure buildup in the storage foramtion is below capillary entry pressure of confining formations. • Invaded CO 2 dissolves over time, which implies little effect on safe storage. • Permeability and maximum capillary pressure mainly control CO 2 invasion. This study investigated the combined effects of dry-out in storage formation in the presence of confining formations on fluid flow during geological carbon sequestration. Numerical simulations demonstrated that dry-out significantly decreased the liquid pressure in the storage formation, and this led to a capillary-driven backflow of water from the confining formations to the storage formation, causing a gradual decrease in the liquid pressure in the confining formations. Finally, CO 2 invaded the confining formations, despite the gas pressure buildup in the storage formation by CO 2 injection being maintained below the capillary entry pressure of the confining formations. Long-term simulations demonstrated that invaded CO 2 in confining formations can almost completely dissolve into unsaturated formation water after shut-in, indicating almost no long-term risk for safe storage or the effectiveness of structural trapping. Sensitivity analysis demonstrated that the permeability of the confining formations and maximum capillary pressure are crucial for controlling the quantity of CO 2 invasion and that injecting CO 2 from a deep section of the storage formation can prevent or sustain CO 2 invasion into the overlying formation. These findings provide valuable insights for optimizing CO 2 storage operations and ensuring the long-term stability of geological carbon sequestration. [ABSTRACT FROM AUTHOR]

• First techno-economic evaluation for new carbonate-based CO 2 capture process. • Simulation model based on previous experimental results is created. • Regeneration of the absorbent at only (∼65 °C), enables the use of waste heat. • Capture cost is EUR 114–133/t, which is higher compared to amine absorption. • Several potential means to improve the process performance are discussed. A simulation model was developed, and a techno-economic analysis (TEA) was conducted for a novel carbon dioxide capture process based on sodium carbonate solution. The key innovation in this process is the incorporation of a microbubble generator, which significantly enhances mass transfer and improves reaction rate. The model, based on prior experimental data, was used to evaluate CO 2 capture costs for the non-optimized base case, identify key cost factors, and assess potential process improvements. The base case capture cost was estimated at EUR 114–133/tCO 2 , which is higher than typical costs for amine absorption. The high costs are largely due to the high liquid flow rates required for efficient mass transfer and the need to maintain low solution concentrations to prevent salt precipitation. A notable advantage of the process is its low-temperature regeneration (∼65 °C), which enables the use of waste heat. When waste heat is available at no cost, capture costs could be reduced by EUR 30–40/tCO 2. The use of a heat pump was found to be economically favorable when heat costs exceed EUR 13–20/MWh, depending on electricity prices. Increasing absorption pressure and temperature were found to be promising means for improving the process performance. [ABSTRACT FROM AUTHOR]

CO 2 capture, utilization, and storage is a key technology to mitigate the climate crisis, and the development of a CO 2 infrastructure is critical for its future large-scale implementation. Successful deployment of a CO 2 infrastructure depends largely on the compatibility between industry links, which is currently limited by unaligned CO 2 purity specifications. Therefore, there is a need to understand the economic and technical implications of purity specifications throughout the whole value chain. This work presents, a highly detailed study encompassing the entire CO 2 conditioning system, including compression, dehydration, liquefaction, and purification. A single, common CO 2 conditioning system derived from operational facilities and designed for post-combustion CO 2 feeds was applied for conditioning of four different feed gases. The investigation includes a techno-economic analysis considering capital and operational expenses for twelve different combinations of CO 2 feed streams and outlet product specifications. The feed sources represent a range of CO 2 purities from high purity to low purity and were derived from post-combustion, pre-combustion, and oxy-fuel combustion processes, while the considered product specifications include CO 2 storage in depleted gas fields, saline aquifer, and utilization in the food industr. For the investigated systems, it is found that low-purity CO 2 was the most expensive source gas to condition to commercial specifications due to a high content of non-condensable gases. The levelized costs for CO 2 conditioning amounted to approximately 25 EUR/t CO 2 , 27 EUR/t CO 2 , 34 EUR/t CO 2 , and 46 EUR/t CO 2 for the investigated high purity, medium-high purity, medium-low purity, and low purity CO 2 cases, respectively. In the investigated cases, only the specifications of low-volatile species were relevant. The impurity limit specifications were relatively close across the investigated commercial specifications, therefore, these did not show significant cost differences. The study clarifies the economic impact on the CO 2 conditioning process from imposing equivalent purity constraints on CO 2 from different sources. [Display omitted] • Common CO 2 transport infrastructure needs aligned industrial CO 2 purity standards. • In-depth study on CO 2 conditioning: Compression to purification and liquefaction. • Techno-economic analysis in elaborate detail for high precision cost estimates. • Feed gas impurity level was primary driver of cost rather than CO 2 specifications. • Cost of conditioning from low-purity CO 2 was twice that of high-purity. [ABSTRACT FROM AUTHOR]

• 8.80 MMt CO₂ can be captured annually from Colorado's nine largest emission facilities at 90 % rate. • Wattenberg field has the highest storage capacity of 443 MMt among oil and gas fields. • Saline aquifers in Colorado offer 54 Gt of storage, with Denver and Palisade having the most potential. • Normalized storage capacity is 0.0025 MMt/sq-mile/ft for oil/gas formations and 0.0018 MMt/sq-mile/ft for saline aquifers. • CO₂-EOR in Wattenberg can store 18 % of injected CO₂, reducing emissions per barrel by 76 %. Carbon Capture, Utilization, and Sequestration (CCUS) is widely considered essential to mitigating anthropogenic climate change. This study, supported by the regional U.S. Department of Energy (DOE) initiative, Carbon Utilization and Storage Partnership (CUSP), evaluates the potential, progress, challenges, and economics of CCUS in Colorado, USA. We examine carbon capture, transportation, and storage potential in oil and gas reservoirs, saline aquifers, and CO₂-enhanced oil recovery (EOR) operations. Additionally, we conduct an economic analysis and discuss the leakage risks posed by legacy wells, which may impact the safety and security of CO₂ storage. It was found that the nine facilities with the greatest CO 2 emissions in Colorado overlie the Denver-Julesburg (DJ) Basin, and half of these are in the Wattenberg field. The DJ Basin, especially the Wattenberg field, is the top-ranked carbon storage target in Colorado for this reason, as well as because: 1) low-permeability formations (Niobrara and Codell) can be used for enhanced oil recovery, and 2) stacked saline aquifers, such as the Dakota, Entrada, Fountain, Lyons, and Morrison Formations, have a high capacity for carbon storage. Through a refined analysis of the efficiency factor, our study provides more accurate assessments of storage capacity, demonstrating that saline aquifers possess significantly higher carbon storage capacities than oil and gas reservoirs. In the Wattenberg field, simulation studies demonstrate that approximately 18 % of injected CO₂ can be stored over a four-year CO₂-EOR process. Additionally, CO₂-EOR reduces overall CO₂ emissions per barrel of oil by 76 % compared to conventional production methods. Economic analysis indicates that CO₂-EOR is an effective approach to offset the high costs associated with CCUS. [ABSTRACT FROM AUTHOR]

• Physical solvent absorption pilot plant operated with coal&biomass derived syngas. • Co-gasification of coal and biomass produced hydrogen rich syngas. • Pre-combustion carbon capture is required for negative CO 2 emissions. • Steady plant performance with only minor accumulation of organic gas species. • Traditional CO 2 physical solvents suitable with novel gasification feedstocks. Advances in co-gasification of coal and biomass are resulting in more interest in poly-generation facilities that can produce hydrogen rich syngas for producing chemicals, fuels and energy, with much lower carbon emissions. When biomass is blended with hydrocarbon feedstocks like coal (biomass cofiring) and when the carbon dioxide (CO 2) produced during the gasification process is captured using pre-combustion CO 2 capture technologies, it is possible to emit less CO 2 into the atmosphere than it took to grow the biomass material, resulting in net negative or low CO 2 emissions. Here, we present the first carbon capture pilot plant data for CO 2 removal from coal and biomass derived syngas using physical solvent absorption. The physical solvent (DEPG at 35.0 L· h −1 and 10.5 °C) was tested in a packed absorption column under pre-combustion CO 2 capture conditions using the biomass derived syngas mixtures (3.54 MPa at 3.4 std. m3· h −1 and 53.1 °C) to assess any changes in the absorption process resulting from co-gasification. Overall, the CO 2 absorption performance of the solvent did not appear to be impacted by the varying feedstock compositions as indicated by average CO 2 removal efficiency of 97.3 % with a standard deviation of 1.6 % across all trials. Despite minor accumulation of organic gas species in the solvent and gas streams exiting the absorber, there did not appear to be any strong correlations between CO 2 capture performance and coal type or biomass type or mixture concentration. These results indicate traditional physical solvent absorption processes can be used with minimal impact from novel gasification feedstock mixtures including coal, wood and corn stover mixtures, but longer term testing is recommended to fully assess the impact of accumulating inorganic and organic species from biomass feedstock. [Display omitted] [ABSTRACT FROM AUTHOR]

• Large-scale CDR for 500–1750 GtCO 2 negative emissions technically feasible • Ca. 12.0–37.5% additional primary energy demand required for ambitious 1.0°C target • Low energy and high security portfolios require +10% primary energy vs 1.5°C target • About 0.42–0.65% of global GDP sufficient to limit global warming to 1.0°C • Mineralisation, e-materials, and desalination-based afforestation are promising Carbon dioxide removal (CDR) is essential to achieve ambitious climate goals limiting global warming to less than 1.5°C, and likely for achieving the 1.5°C target. This study addresses the need for diverse CDR portfolios and introduces the LUT-CDR tool, which assesses CDR technology portfolios aligned with hypothetical societal preferences. Six scenarios are described, considering global deployment limitations, techno-economic factors, area requirements, technology readiness, and storage security for various CDR options. The results suggest the feasibility of large-scale CDR, potentially removing 500–1750 GtCO 2 by 2100 to meet the set climate targets. For a 1.0°C climate goal, CDR portfolios necessitate 12.0–37.5% more primary energy compared to a scenario without CDR. Remarkably, funding a 1.0°C target requires only 0.42–0.65% of the projected global gross domestic product. Bioenergy carbon capture and sequestration and rainfall-based afforestation play limited roles, while secure sequestration of captured CO 2 via direct air capture, electricity-based carbon sequestration, and desalination-based afforestation emerge as more promising options. The study offers crucial techno-economic parameters for implementing CDR options in future energy-industry-CDR system analyses and demonstrates the tool's flexibility through alternative assumptions. It also discusses limitations, sensitivities, potential trade-offs, and outlines options for future research in the area of large-scale CDR. [ABSTRACT FROM AUTHOR]

• Swelling effect due to shale-CO 2 interaction is simulated using pore network modelling. • Shale micropores and mesopores are considered for shale swelling causing fracture size change at pore-scale. • Low-density fractured shales fracture aperture size is impacted twice as that of high-density fractured shales. • Gas slippage contributes to 10–20 % of the total permeability in CO 2 injection pressures <10 MPa. Underground CO 2 storage is a key strategy to achieving net-zero targets by 2050, which requires gigatonne-scale containment of gaseous CO 2 in geological formations. Shale rocks play a role in both trapping CO 2 and preventing its escape, thus ensuring containment security. However, shale integrity can be compromised upon interaction with CO 2 , which should be carefully evaluated. This study explores the dynamic behaviour of CO 2 -shale interaction at the pore scale, focusing on the physiochemical interactions between CO 2 and shale, including the impact of shale swelling, where CO 2 adsorption causes matrix deformation and alters fracture sizes. Here, we utilise image-based analyses to develop a triple-porosity pore network model (PNM), reflecting the complex nano- to micro-scale structure of shale, to examine CO 2 injection into methane-saturated environments. The study particularly focuses on the impact of matrix deformation caused by gas sorption (swelling), competing with mechanical stress effects. Findings indicate that CO 2 injection leads to a reduction in fracture permeability by up to 17 % and 10 % in low- and high-density fractured shales, respectively, under high confining pressure (50 MPa), and by 15.5 % and 8 % under lower confining pressure (25 MPa). Although fracture permeability versus CO 2 injection pressure reduces monotonically at the lower confining pressure, that of the higher confining pressure is non-monotonic, where the fracture permeability shows an increase due to effective stress change. Additionally, the average fracture aperture size decreases by 50 nm in low-density and 25 nm in high-density fractured shales, highlighting the critical balance between swelling effects and mechanical stresses in the geological sequestration of CO 2. [ABSTRACT FROM AUTHOR]

Recent United States Department of Energy (DOE) sponsored front-end engineering design (FEED) studies for retrofitting existing fossil-fueled power plants with state-of-the-art carbon capture technology contain previously overlooked real-world design considerations for near-term deployment of carbon capture. Insights from examining seven recently published FEED study reports are summarized in this paper. This includes a discussion of the design, performance, and cost implications associated with (1) location-specific considerations such as water availability, land availability, and accessibility; (2) host-plant-specific factors such as flue gas specifications, allowable degree of integration between the capture system and host plant, and operational mode; and (3) miscellaneous factors such as market conditions, permitting requirements, and business case incentives. This manuscript highlights (1) water availability as a key design and cost driver, with host plant steam extraction increasing capture system cooling water availability, (2) modularization and constructability impacts on the number of capture trains, (3) the impacts of host plant operational mode and capacity factor on the business case for installing capture, and (4) the merit of continued research, development, and demonstration efforts addressing steam extraction, host plant tie-in at the stack, solvent reclamation and air emissions control. [ABSTRACT FROM AUTHOR]

• Reduced aqueous mobility with gas injection observed numerically and experimentally. • Mineral dissolution with CO 2 injection showed minor impact on tracer migration. • Conventionally generated static geologic models were insufficient for tracer modeling. • Nonaqueous-soluble tracers showed bypassing of production wells. • Tracer modeling was moderately sensitive to petroleum model component count. A series of six aqueous-soluble and four nonaqueous-soluble tracer experiments and corresponding numerical simulations were executed for the Farnsworth Field in Ochiltree County, Texas, USA, a field which is undergoing tertiary enhanced oil recovery with water-alternating-gas (WAG) production. The combination of field experiments and numerical simulations was designed to identify flow pathways between injectors and producers and potential short circuiting of injected fluids. Field recoveries of aqueous-soluble tracers were dependent on the WAG stages of the tracer injection well, with shorter arrival times for strictly waterflooding and delayed arrival times for alternating injection stages. Aqueous-soluble tracer (i.e., 1,3,6-naphthalene trisulfonate, 1,5-naphthalene disulfonate, 1,6-naphthalene disulfonate, 2-naphthalene sulfonate, 2,6-naphthalene disulfonate, and 2,7-naphthalene disulfonate) arrivals for WAG injectors indicated water bypass was occurring during gas injection stages. Nonaqueous-soluble tracer (i.e., perfluoro-1,2-dimethylcyclohexane, perfluoroethylcyclohexane, perfluoromethylcyclohexane, and perfluoromethylcyclopentane) experiments revealed faster migration velocities than for the aqueous-soluble tracers and flow heterogeneities that resulted in the tracers bypassing nearer production wells. Base-case numerical simulations of the tracer experiments used a geologic model of the Morrow B sandstone production interval with parameters calibrated from history matching simulations, with the Morrow B sandstone sub-divided into hydrologic flow units (HFUs). Alternative simulation scenarios investigated HFU-dependent three-phase relative permeability models and dynamic intrinsic permeability enhancement with exposure to aqueous-dissolved CO 2. Compositional petroleum models with four components were shown to be sufficient for tracer modeling compared against a nine-component model, with a factor of four difference in simulation execution time. HFU-dependent relative permeability models and dynamic intrinsic permeability modifications influenced arrival times and production concentrations of both aqueous- and nonaqueous-soluble tracers but did not yield unique flow pathways compared to those observed in the base-case scenario. [ABSTRACT FROM AUTHOR]

• Permian Basin with over 7000 oil and gas fields producing 40 % of U.S. oil and 15 % of U.S. gas is a promising region for carbon capture utilization and storage. • We examined the cost effectiveness and economic feasibility of deployment of Carbon Capture and Storage for Midstream processing facilities with Acid Gas Injection wells. • We found that our estimated cost for CCS deployment in AGI is lower than that for the coal fired power plant, natural gas fired power plant, and bioenergy with carbon capture and sequestration. • With section 45Q tax credits for 12 years, we found that any existing facilities with an annual injection rate over 10,000 MT are economically viable to deploy CCS and for new AGI wells construction the rate should be 100,000MT. Carbon capture, utilization, and storage (CCUS) is an important pathway for meeting climate mitigation goals. While the economic viability of CCUS is well understood, previous studies do not evaluate the economic feasibility of carbon capture and storage (CCS) in the Permian Basin specifically regarding the new Section 45Q tax credits. We developed a technoeconomic analysis method, evaluated the economic feasibility of CCS at the acid gas injection (AGI) wells, and assessed the implication of Section 45Q tax credits for CCS at the AGIs. We find that the compressors, well depth, and the permit and monitoring costs drive the facility costs. Compressors are the predominant contributors to capital and operating expenditure driving the levelized cost of CO 2 storage. Strategic cost reduction measures identified include 1) sourcing of low-cost electricity and 2) optimizing operational efficiency in well operations. In evaluating the impact of the tax credits on CCS projects, facility scale proved decisive. We found that facilities with an annual injection rate exceeding 10,000 MT storage capacity demonstrate economic viability contingent upon the procurement of inputs at the least cost. The new construction of AGI wells were found to be economically viable at a storage capacity of 100,000 MT. The basin is heavily focused on CCUS (tax credit – $65/MT CO 2), which overshadows CCS ($85/MT CO 2) opportunities. Balancing the dual objectives of CCS and CCUS requires planning and coordination for optimal resource and pore space utilization to attain the basin's decarbonization potential. We also found that CCS on AGI is a lower cost CCS option as compared to CCS on other industries. [ABSTRACT FROM AUTHOR]

Given the urgent need to mitigate increasing CO 2 emissions and alleviate the climate crisis, amine-based post-combustion capture (PCC) processes have emerged as a prominent method to reduce the emissions from industrial point sources. While many technological advancements have been introduced for such processes, leading to decreased energy requirements for capture, there are still only a few commercial installations because of their high costs. Therefore, these processes can benefit from process optimization to enhance their economic viability. This work presents a new open-source, rate-based, equation-oriented model of a novel PCC process that uses piperazine as the amine solvent. The model was implemented in Python, in accordance with the Pyomo-based IDAES modeling and optimization framework. The proposed nonlinear model can be used for both simulation and optimization. To ensure its robust convergence, we further devise a rigorous, multi-level cascade initialization scheme, whose principles can further be applied towards the initialization of similar process models. The model was validated with published pilot plant data and then optimized for pilot and commercial scales with an economic objective that considers both capital and operational costs. Results show that process optimization can indeed improve the economics of this technology, leading to 15.6% yearly savings at the pilot scale compared to the baseline case considered in the study. Additional parametric analyses were performed to understand how the flue gas flowrate and CO 2 concentration, as well as the target capture rate, affects the cost of capture. • PZ/AFS process model, equation-oriented, built open-source in IDAES modeling platform. • Homotopy initialization strategy helps model converge for wide range of plant scales. • Detailed economic model in accordance with latest PCC costing protocols. • Economic optimization results for both coal-fired and NGCC fuel gas sources. • Parametric analyses on feed gas flowrate and composition, and key operating variables. [ABSTRACT FROM AUTHOR]

Calcium looping (CaL), typically capable of reducing CO 2 emissions by approximately 90%, is a technology well suited to capturing CO 2 emissions from a wide array of industrial processes. An approach in which Ca(OH) 2 is injected into the carbonator to increase the carbon capture efficiency of the CaL process to 99% was evaluated in this study using a one-and-a-half-dimensional reactor model. The effect of several key parameters was considered, including the injection flow rate, injection elevation, and the formation rate of CO 2 in the freeboard of the carbonator due to the combustion of char particles elutriated from the calciner. The main finding was that capture rates of 99% appear attainable, given that enough Ca(OH) 2 is injected and that the injection occurs at a suitable location, i.e., the sorbent is allowed sufficient residence time in the reactor. • Carbon capture rates of 99% appear attainable with a Ca(OH) 2 injection. • The elevation at which Ca(OH) 2 is injected significantly affects its performance. • CO 2 potentially formed in the carbonator is largely captured, given enough Ca(OH) 2. [ABSTRACT FROM AUTHOR]

• Membrane process for CO 2 /O 2 separation at AEM-based CO 2 electrolyzers is designed. • CO 2 separation cost is minimized by optimizing the membrane areas. • Economic and environmental indicators are compared with amine scrubbing. • Membrane process is competitive when CO 2 /O 2 ratio of anode outlet stream is high. • Membrane process will become more promising when greener electricity is available. Anion exchange membrane (AEM)-based electrolysis for CO 2 reduction reaction (CO 2 RR) has garnered attention as a promising carbon dioxide utilization technology due to its superior energy efficiency at high current densities. The major drawback of AEM-based electrolysis for CO 2 RR is CO 2 crossover, which leads to the loss of introduced CO 2 feedstock and thus detrimentally affects the process's overall economic and environmental viability. We design a 3-stage membrane-based CO 2 recovery unit to capture CO 2 from the mixture of CO 2 and O 2 discharged from the anode side of AEM-based CO 2 electrolyzers. The membrane area is optimized via a hybrid of genetic algorithm and 'fmincon' in MATLAB. The estimated CO 2 capture cost ranges from 43.3 to 109.3 USD/tCO 2 , which is economically comparable to piperazine-based amine scrubbing units when recovering CO 2 at a purity of up to 99.5 mol.% under a CO 2 /O 2 molar ratio of 1.5∼2. The carbon footprint of the designed process ranges from −0.936 to −0.838 tCO 2 eq/tCO 2 -captured, indicating superior environmental performance compared to those of the piperazine-based amine scrubbing units. [ABSTRACT FROM AUTHOR]

Carbon capture and storage (CCS) is forecast to play a significant role towards CO 2 emissions reduction. Cost-effective and simplified monitoring will be essential for rapid adoption and growth of CCS. Seismic imaging methods are regularly utilized to monitor low-velocity anomalies generated by injection of CO 2 in the subsurface. In this study we generate active and passive synthetic seismic datasets at different stages of CO 2 injection in the subsurface based on geologically constrained subsurface models of the Pelican storage site in the Gippsland Basin, Australia. We apply full waveform inversion (FWI) and wave-equation dispersion (WD) inversion to seafloor deployed distributed acoustic sensing (DAS) data to reconstruct the low-velocity anomalies. We model both strain (DAS) and displacement datasets for the active data component of the study and show that they result in similar reconstruction of the CO 2 anomaly. FWI based time-lapse imaging of active data yields the most accurate results. However, this approach is expensive and also suffers from complex issues because of the near-onshore location of the storage site. Alternatively inverting passive data results in only minor differences, but can still effectively monitor changes in the subsurface, and assist in monitoring the CO 2 plume at the reservoir depth. Furthermore, we demonstrate the capability of WD for inverting Scholte-waves derived from ambient noise for shallow detection of CO 2 in the unlikely event of a leakage. Therefore, we propose a mixed mode monitoring strategy where passive data is utilized for routine monitoring while active surveys are deployed only when further investigation is required. • Multifaceted monitoring of a modelled CO 2 plume using passive and active synthetics based on an offshore CO 2 sequestration site in Australia. • Shows that imaging surface distributed acoustic sensing data with wave-equation methods can cost-effectively monitor carbon capture and storage. • Early arrival waveform inversion produces comparable results for distributed acoustic sensing and conventional seismic data. • Wave equation imaging of passive DAS data enables routine monitoring, limitng the need for active surveys. [ABSTRACT FROM AUTHOR]

• Well records enable assessment of hazards and the feasibility of corrective action. • Proposed framework ranks wells based on challenge of corrective action. • Well rankings are valuable for screening potential areas of interest. • Majority of wells considered do not isolate Miocene GCS targets. Federal offshore waters in the Gulf of Mexico are of interest for large-scale geologic carbon storage (GCS). However, more than 80,000 offshore oil and gas wells exist in the region, which could impact the integrity of sealing intervals. In this study, we propose a screening methodology for ranking offshore legacy wells based on the challenge they may present to GCS. The methodology relies on the review of well regulatory records to 1) identify leakage pathways and assess the potential hazards that wells pose to planned GCS operations, 2) evaluate well features that impact the accessibility of wells to determine the feasibility of potential corrective actions, and 3) rank wells based on the overall challenge they may pose for GCS. We demonstrate our framework by evaluating the construction and abandonment of 156 wells across eight areas of interest (AOIs) in shallow federal waters along the Texas Gulf Coast. The majority (99.3 %) of wells considered were constructed and plugged in a manner that did not isolate prospective GCS targets in the Upper and Lower Miocene formations and may potentially require a challenging or uncertain corrective action prior to GCS. Dataset trends suggest that the observed well construction and plugging designs may be common in shallow offshore federal waters along the Texas Gulf Coast. Consequently, operators pursuing offshore GCS projects in the region may consider selecting areas that avoid challenging wells or performing robust evaluations of legacy well leakage risks to plan corrective action prior to CO 2 injection. [Display omitted] [ABSTRACT FROM AUTHOR]

Basalt-based CO 2 mineralization offers gigaton-scale capacity for sequestering anthropogenic CO 2 , but it faces challenges such as low cation productivity and formation of pore-clogging clays. A potential solution is to treat the basalt with aqueous acids such as HCl, a by-product of some electrochemical CO 2 removal processes. To date, our understanding of basalt-acid interactions is limited to extrapolations from higher pH environments, and therefore little is known about the mechanisms of the reaction at acidic conditions. To address this knowledge gap, far-from-equilibrium dissolution rates of basaltic glass and crystalline basalt were measured in mixed flow reactors at pH 0 to 9, and temperatures from 23 to 60 °C, with a specific focus on the low-pH region. Measured geometric surface area-normalized dissolution rates can be described according to: k = 1 0 − (5. 6 ± 0. 5) ⋅ exp − 42. 2 ± 2. 0 R ⋅ 1 T − 1 T r ⋅ a H + (0. 81 ± 0. 02) + 1 0 − (10. 9 ± 0. 3) ⋅ exp − 32. 5 ± 1. 1 R ⋅ 1 T − 1 T r ⋅ a H + − (0. 15 ± 0. 01) where k is the rate constant (mol m−2 s−1) at any temperature T (Kelvin) and H + activity (a H + ), T r is the reference temperature (298.15 K), and R is the ideal gas constant (8.314 × 10-3 kJ mol−1 K−1). The combined results of kinetic experiments and geochemical modeling indicate that acid reaction with basalt yield orders of magnitude faster cation release rates, effectively neutralizes fluid pH, and limits clay formation by limiting Si release into the system. [Display omitted] • Acid pre-treatment of basalts leads to rapid cation releases to mineralize CO 2. • First experimental data of basalt dissolution kinetics in acidic environments. • Basalt dissolution in acid is strongly non-stoichiometric. • The lack of Si-release prevents the formation of pore-clogging clays. • Acid neutralization potential of basalt depends on water/rock ratio. [ABSTRACT FROM AUTHOR]

• A novel surrogate model-based reinforcement learning method is proposed for optimizing CO2 geological storage. • The E2CO model translates to high-fidelity models well and demonstrates robustness in predicting model states and well outputs. • The surrogate model-based reinforcement learning approach achieves efficient training and is adaptable for various optimization tasks. Injecting greenhouse gas (e.g. CO2) into deep underground reservoirs for permanent storage can inadvertently lead to fault reactivation, caprock fracturing and greenhouse gas leakage when the injection-induced stress exceeds the critical threshold. It is essential to monitor the evolution of pressure and the movement of the CO2 plume closely during the injection to allow for timely remediation actions or rapid adjustments to the storage design. Extraction of pre-existing fluids at various stages of the injection process, referred as pressure management, can mitigate associated risks and lessen environmental impact. However, identifying optimal pressure management strategies typically requires thousands of simulations, making the process computationally prohibitive. This paper introduces a novel surrogate model-based reinforcement learning method for devising optimal pressure management strategies for geological CO2 sequestration efficiently. Our approach comprises of two steps. The first step involves developing a surrogate model using the embed to control method, which employs an encoder-transition-decoder structure to learn dynamics in a latent or reduced space. The second step, leveraging this proxy model, utilizes reinforcement learning to find an optimal strategy that maximizes economic benefits while satisfying various control constraints. The reinforcement learning agent receives the latent state representation and immediate reward tailored for CO2 sequestration and choose real-time controls which are subject to predefined engineering constraints in order to maximize the long-term cumulative rewards. To demonstrate its effectiveness, this framework is applied to a compositional simulation model where CO2 is injected into saline aquifer. The results reveal that our surrogate model-based reinforcement learning approach significantly optimizes CO2 sequestration strategies, leading to notable economic gains compared to baseline scenarios. [ABSTRACT FROM AUTHOR]

• Adsorption process using a flexible metal-organic framework ELM-11 is optimized. • Surrogate models are developed for vacuum pressure swing adsorption process. • Process models with hysteresis and sigmoidal isotherms are successfully optimized. • Pareto front is analyzed for recovery, energy consumption, and bed size factor. • ELM-11 shows high purity consistently owing to high selectivity. This study presents a process optimization study for a vacuum pressure swing adsorption (VPSA) process using a flexible metal-organic framework (MOF), which is gaining attention as a material to realize energy-efficient carbon dioxide capture processes. Many flexible MOFs exhibit sigmoidal adsorption isotherms with hysteresis, posing a challenge for simulation and optimization using a rigorous process model. In this study, we employ surrogate model optimization, where surrogate models using machine-learning algorithms were constructed from simulation of 903 operating conditions generated by Latin hypercube sampling. The surrogate models with the best performance were identified from 18 different surrogate options considering four design variables—adsorption pressure, desorption pressure, adsorption time, and desorption time. Using the best surrogate models, a multi-objective optimization problem was solved to identify the Pareto front among recovery, energy consumption, and bed size factor. Our analysis identified a distinct characteristic of VPSA using a flexible-MOF where purity and recovery are hardly affected by the feed volume. [ABSTRACT FROM AUTHOR]

• Kazakhstan's CO 2 emissions come from electricity sectors concentrated in the North. • Eight CCUS hubs in Kazakhstan aim to capture 115 Mt of CO 2 annually by 2060. • Ammonia and natural gas plants are prime candidates for CCUS. • Atyrau hub shows high CO 2 capture rates at relatively low costs. • Kazakhstan's CCUS hub infrastructure needs US$84.2 billion. The competitiveness of both the power and industry sectors in Kazakhstan is due to the use of cheap fossil fuels. Due to the projected large-scale deployment of renewable energy sources in the future, some portions of cheap coal and hydrocarbon use are planned to be phased out in Kazakhstan. In its net-zero journey, the country still intends to have GHG emissions from reduced use of fossil fuels and "hard-to-electrify" industries such as chemicals, cement, and iron/steel sectors. Carbon capture and storage (CCS) is a decarbonization solution to existing fossil fuel-fired power plants and other hard-to-abate industries in the net-zero age, which Kazakhstan officially plans to reach by 2060. This study covers three major research tasks on large-scale CCS deployment in Kazakhstan. The study first reveals the "low-hanging fruits" of CO 2 capture in the natural gas processing and ammonia production industries, with a low cost of capture of $29 per ton of CO 2 captured each, by comparing the costs of capture in Kazakhstan with those of power plants, steel factories, cement plants, refineries, and hydrogen plants. Secondly, this work shows that developing CCS projects in hubs of multiple emitters can bring cost-efficient deployment of CCS in Kazakhstan. Lastly, we presented our vision of how CCS could be a part of Kazakhstan's big net-zero plan in 2060. Our estimates show that 8 CCS hubs in Kazakhstan with a total capacity of 115 Mt CO 2 /year could cost $87 billion in capital expenditures (CAPEX) until 2060. While CO 2 capture remains the most expensive component of CCS process chains globally, compressing and transporting CO 2 poses significant cost challenges in Kazakhstan due to the long distances between emission sources and storage sites. Future research endeavors could explore automated tools to optimize logistical considerations and enhance the accuracy of cost estimations. Moreover, further studies should incorporate site-specific data to reduce assumptions and refine CCS potential assessments in Kazakhstan. [Display omitted] [ABSTRACT FROM AUTHOR]

• Feasibility of storing the acid gas produced from facilities into basal sand aquifer. • Using a wellbore-aquifer-compositional model to investigate pressure induced around faults. • Simulation of plume migration, pressure changes, and CO 2 storage capacity. • Incorporating fault transmissibility, solubility, salinity, hysteresis, trapping and compositional tracking. • Substantial pressure increases around the sealing fault can be observed. • Relocating storage site away from fault or using a horizontal well to mitigate pressure buildup. This study investigates the feasibility of storing the acid gas produced from the oil and gas facilities in Southern Saskatchewan into the Basal Sand aquifer using a coupled wellbore-aquifer-compositional reservoir model. The simulations investigate the pressure change around the fault in proximity of the primary storage location incorporating the influence of reservoir permeability, fault transmissibility, and wellbore configuration, on the factors critical to safe and efficient storage, such as plume migration, pressure changes, and CO 2 storage capacity. A compositional fluid model created using an equation of state was integrated into the reservoir model. Simultaneous incorporation of fault transmissibility, phase solubility, water salinity, temporal in-situ hysteresis and structural trapping, and in-situ compositional tracking of individual gas components is considered as the main novelty of this work. The main challenge of the study was the lack of available data to characterize the aquifer. To this end, a comprehensive workflow of reservoir studies and modeling was applied to reduce the uncertainties and evaluate the site selection. The Basal sand scoping models reveal that the aquifer is expected to handle the required disposal volume given its extent. The injected acid gas plume migrates laterally and preferentially towards the northwest, away from the fault, owing to the aquifer's geological structure. CO 2 remains entirely in the supercritical state, offering storage advantages due to its lower volume. The reservoir permeability significantly impacts the pressure patterns with lower permeability formations triggering higher wellhead injection pressures. Substantial pressure increases around the sealing fault can be observed. Pressure changes of 110 kPa (16 psi) to over 400 kPa (58 psi) were observed at the fault segment after 20 years of continuous gas injection for the expected range of reservoir properties. Mitigation strategies to minimize the increase in fault pressure entail relocating the injection site away from the fault or utilizing a horizontal well trajectory and using an observation well near the fault for monitoring any pressure buildup and slippage. [ABSTRACT FROM AUTHOR]

• We study formate species, a product of CO 2 electrochemical reduction, as an alternative carbon carrier for sequestration and EOR • Formate solution injection yielded greater levels of oil recovery and net carbon storage • Carbon-bearing species resided in the dense aqueous phase without having to rely on petrophysical trapping mechanisms • In establishing carbon tax credit policies and regulations, policymakers should include alternative carbon carriers. As carbon capture, utilization, and storage (CCUS), carbon-dioxide enhanced oil recovery (CO 2 EOR) has inherent shortcomings, such as inefficient oil recovery and carbon storage, and low storage security with mobile CO 2. This paper presents a techno-economic-environmental analysis of using formate species, a product of CO 2 electrochemical reduction, as an alternative carbon carrier for sequestration and EOR in a carbonate oil reservoir in the Gulf of Mexico Basin. CO 2 injection, water-alternating-CO 2 injection, and aqueous formate solution injection were compared using a compositional reservoir simulation model and an economic calculator. Formate solution injection yielded greater levels of oil recovery and net carbon storage, where the carbon-bearing species resided in the dense aqueous phase without having to rely on petrophysical trapping mechanisms (structural and capillary). The enhanced oil production, net carbon storage, and storage security can be promoted by providing formate-based CCUS with more incentives (e.g., greater tax credit) in comparison to CO 2 -based CCUS for EOR and the manufacture of chemicals and products. In establishing carbon storage incentive policies and regulations, policymakers should include alternative carbon carriers. [ABSTRACT FROM AUTHOR]

• A surrogate-assisted framework for efficient stochastic optimization of amine scrubbing CO 2 capture process. • Multi-objective optimization runs were implemented to find the optimal operating points for different flue gas CO 2 concentration and desired capture levels. • Each optimization run with laborious model evaluations took only 10–40 min. Amine scrubbing processes for post-combustion CO 2 capture have been extensively studied and significantly improved via various novel designs. However, the amine scrubbers implemented nowadays were usually not optimized according to a number of different evaluation criteria. This is often due to the fact that, for high dimensional design spaces, the rigorous simulation runs needed to facilitate process optimization always calls for huge numbers of simulation software accesses and overwhelming iterative calculations. Therefore, in this study, the well-trained surrogate model was adopted to replace its rigorous counterpart for the purpose of ensuring efficient optimization runs in practical applications. In current study, two objectives, i.e., the specific equivalent work and the CO 2 capture level, were both rapidly and effectively optimized in various practical scenarios with different flue gas CO 2 concentrations. The corresponding operational parameters and utility consumptions were also easily obtained without additional effort. The computation results obtained so far showed that the proposed surrogate-assisted approach can be utilized to significantly reduce the computational load in practice. [ABSTRACT FROM AUTHOR]

• A model based on barrier options that account for investors' risk aversion and technical risk is a suitable approach to mitigating the technical risk of CCUS projects. • Triggering immediate investments in one-step CO2-DME projects under current economic conditions is only feasible if extensive research and development are carried out to reduce production costs. • As H2 production costs are prominent in the project's OPEX, future advances in H2 production technology will significantly impact CCUS projects' profitability. • Carbon policies directly impact CCUS projects' value, and if the carbon tax exceeds the cost of carbon capture costs, investment will intensify. Carbon capture, utilization, and storage (CCUS) technology is effective and value-adding solution for reducing emissions. However, the development and commercialization of these technologies are challenging due to high investment costs and several uncertainties. This study develops a novel comprehensive real-options-based model to evaluate investment in CCUS projects considering the technical risk and the investor's risk aversion. This study proposed an exotic compound real options model that combines American and barrier options. First, applying the Poison process, the technical risk is explicitly modeled. Secondly, the investor's risk aversion is defined as a barrier level for the barrier option part of the proposed model. Thirdly, the value of the project is evaluated through the exotic compound real option. Finally, we assess the economic viability of the project under multiple scenarios. The results of implementing the model for a real case show that the integrated technical risk assessment and the barrier option appropriately address investors' risk aversion. Furthermore, the comparison indicates that the proposed compound real options model is more effective than the traditional NPV (Net Present Value). Regarding policymaking, the results reveal that setting an appropriate carbon tax that considers the costs of carbon capture would be more beneficial. Further, the model provides investors helpful guidance to make proper investment decisions for CCUS technology projects under uncertainties. [ABSTRACT FROM AUTHOR]

• We perform a pre-screening analysis for the risks of induced seismicity due to a prospective carbon inection operation near Trüllikon, Switzerland. • We follow the concept of a bowtie for risk management, where barriers to prevent threats to the risk are appraised alongside mitigation measures to reduce the severity/likelihood of consequences. • Barriers to threats are appraised through fault slip potential analysis and modelling of expected pore pressure increases due to CO 2 injection. • Mitigation measures are considered though the design of a risk-based traffic light protocol. • We then discuss how these risk management results would translate into monitoring performance targets. Successful carbon injection operations depend critically on the management of risks, like induced seismicity. Here, we consider the bowtie risk management framework to organize pre-screening efforts around a prospective CO 2 injection operation near Trüllikon, Switzerland. First, potential barriers/threats are appraised via a literature review of the regional seismotectonics, hydrogeology, and nearby induced seismicity cases – which suggests a natural propensity for earthquakes because of the proximity to the Neuhausen Fault and a lack of effective underlying hydrogeological barriers. Next, we engineer barriers to fault reactivation by quantifying the fault slip potential. The closest (∼700 m) and most susceptible (∼3.0 km) portions of the Neuhausen Fault would require ∼1.7 MPa and ∼0.47 MPa for reactivation, respectively. The most susceptible (unknown) faults are normal slip (168° strike) that require ∼0.23 MPa for reactivation. Injection simulations indicate pressure changes on Neuhausen Fault segments of 0.01–0.05 MPa – values that are 1–2 orders-of-magnitude smaller than those needed for fault reactivation. These engineered barriers limit the potential for fault reactivation. However, if these barriers prove totally ineffective, we have also designed a traffic light protocol as a reactive mitigation measure. Forecast estimates of nuisance, damage, and fatalities are used to infer the last-possible stopping-point based on a comparison with operation-ending risks encountered at Basel and St. Gallen. This indicates a red- and yellow-lights of M W ∼2.0 and M W ∼0.0, respectively. We synthesize these disparate pre-screening analyses to recommend performance targets for real-time seismic monitoring. Future CO 2 operations will likely find our approach helpful for designing effective risk management. [ABSTRACT FROM AUTHOR]

• Sealing mechanism of ultra-high T/P CO2-rich reservoirs analyzed in the South China Sea. • Hydraulic failure occurred after the capillary failure. • Capillary leakage is not effectively reducing reservoir pressure. Global industry drillings targeted at deep-burial hydrocarbons have renewed the record of maximum sustainable overpressure in sedimentary basins. However, the influence of extremely high overpressure on natural fluid accumulation and artificial waste sequestration is not yet completely understood. To better understand the motion characteristics of the highly overpressured CO 2 -rich fluid, the CO 2 retention capacity was quantified, and the CO 2 -rich fluid motion trails were evaluated in an ideal natural laboratory in the Yinggehai Basin. The hydraulic sealing capacity was higher than the capillary sealing capacity in the highly overpressured stratum. Relative to the situations of no breach or solely breached by capillary failure, the superposition of capillary and hydraulic failures resulted in the caprock integrity breakage by faults (or fractures), diapirs, and pipes. Meanwhile, the high expulsion flux of CO 2 -rich fluid caused the consumption of chlorite to generate illite in the caprock of dual-breached fields. The CO 2 -rich fluid flux of capillary invasion was limited by the inherently low permeability of caprock, which may be insufficient for a dramatic change of hydrogen ions or electron activities to induce remarkable chlorite dissolution in the caprock of the sole-breached field. [ABSTRACT FROM AUTHOR]

Reducing greenhouse gas emissions in the shipping sector is a challenging task. While renewable fuels stand out as the most promising long-term solution, their near- and mid-term viability is hampered by limited availability and high costs. An alternative approach is onboard carbon capture, which can reduce emissions from new ships as well as retrofitted vessels. This paper examines the techno-economic potential of oxyfuel combustion based carbon capture on ships. The oxyfuel concept uses an oxygen-rich atmosphere in the combustion process, resulting in a mixture of carbon dioxide and water. After the condensation of water, the carbon dioxide rich gas can be directly stored on board. Various onboard oxygen supply concepts are investigated, including different technologies for onboard air separation and liquid oxygen bunkering. Influences on the ship energy system are studied by system simulation of a deep-sea container vessel. Benchmarked against a technologically mature post-combustion carbon capture system, the results show that the oxyfuel concepts have limited competitiveness because of reduced engine efficiencies and high energy demands for onboard oxygen supply. Avoiding onboard oxygen supply by using liquefied oxygen as a byproduct from onshore electrolysis increases energy efficiency and the competitiveness of oxyfuel combustion but requires additional storage space. Sensitivity analyses highlight that the engine combustion concept and engine efficiency are the most critical influences on the techno-economic performance. • Oxyfuel combustion faces significant challenges compared to post combustion concepts • High fuel penalty mainly caused by the drop in efficiency of the combustion engine • The use of onboard liquid oxygen storage tanks offers techno-economic advantages • High potential for significantly reduce total CO 2 emissions with oxyfuel combustion [ABSTRACT FROM AUTHOR]

This review describes the main geological and geomechanical aspects of CO 2 -injection projects in the Brazilian Pre-Salt reservoirs, focusing on the storage potential and geomechanical aspects of CO 2 injection. The Pre-Salt reservoirs in the Santos Basin offer favorable conditions for CCS due to their geological characteristics and existing infrastructure. The thick evaporite caprock, primarily composed of halite, acts as an efficient seal against CO 2 migration. The CO 2 -injection in the Pre-Salt has been active since 2010, with significant amounts of CO 2 already stored in the reservoirs. The volumetric assessment estimates the static storage capacity of the Pre-Salt reservoirs to be over 3.3 Gt of CO 2 , considering only the four fields currently undergoing injection. Geomechanical constraints, including the maximum injection pressure and caprock integrity, are crucial considerations for safe CCS operations. The high stress regime and the hydrostatic state of the caprock minimize the risk of fracturing during injection. Furthermore, dynamic storage capacity calculations indicate the feasibility of injecting CO 2 into Pre-Salt reservoirs. This review provides insights into the current state and future prospects of CO 2 -injection projects in the Brazilian Pre-Salt, contributing to the development of sustainable carbon mitigation strategies in the region. • Significant CO 2 storage capacity identified in the Brazilian Pre-Salt reservoirs. • Geomechanical characteristics and evaporite caprock assure the long-term safety of CO 2 storage. • CO 2 -injection in hydrocarbon reservoirs enhance oil recovery (EOR) while avoiding greenhouse gas emissions. • Geomechanical modeling and volumetric approach used to assess storage capacity and safety. [ABSTRACT FROM AUTHOR]

• First study to comprehensively address climate strategies for the O&G upstream sector in Brazil. • Decarbonization scenarios are simulated using a national Integrated Assessment Model (IAM). • O&G production can be sustained without compromising national decarbonization goals, but CO 2 and CH 4 emissions reductions must exceed simulated efforts to match industry leaders. • Ample potential to offset emissions through reforestation (∼ 500MtCO 2 /2050) and BECCS (∼ 400MtCO 2 /2050), presenting appealing business prospects for the industry. • CCS can play a vital role in advancing the decarbonization goals of both the sector and the country. Future projections of oil and gas demand suggest that some production will remain necessary. Although attention often focuses on CO 2 emissions from the combustion of their products, oil and gas production is also a relevant global emission source of both CO 2 and CH 4. Hence, understanding the carbon performance of upstream activities in producing nations is vital for distinguishing producers in a climate-pressured global market. This work explores climate strategies for the oil and gas upstream sector, using Brazil as a case study. The sector´s emissions profile is evaluated under distinct national climate scenarios. The analysis employs BLUES, a national Integrated Assessment Model (IAM), to access production volumes, mitigation measures applicable to the sector, and carbon dioxide removal potentials within the country to eventually offset the sector's remaining emissions. Results indicate sustained oil and gas production over the evaluated horizon (2020–2050) without compromising national climate goals, yet the sector's future emissions trajectory does not align with decarbonization targets pursued by more ambitious oil-producing nations and industry players. Despite sectoral mitigation measures indicated by the model, considerable emissions remain until 2050. Conversely, the country offers ample offsetting opportunities with potential synergies for the sector, especially through BECCS. Furthermore, the acceptability of offsets is discussed. [ABSTRACT FROM AUTHOR]

• A minimum work analysis is done for post-combustion CO 2 capture with solid sorbent. • We find that for a proposed sorbent, thermodynamic limitations make use unfeasible. • Comparison with conventional liquid amine absorption shows higher energy cost. • Sensitivity of different process variables provides insight into potential improvements. • Thermodynamic analysis provides a pre-screening tool for future sorbent evaluation. There has been an increased interest in the use of solid sorbents for CO 2 capture from flue gases to reduce emissions from fossil energy. This work uses a simple Carnot engine-like model to compare the energy requirements for a CO 2 capture process using a solid adsorbent in a circulating fluidized bed with its minimal thermodynamic needs and with the performance of a conventional liquid solvent process. The energy requirements for CO 2 capture using thermal swing separation sorption are dominated by the standard Gibbs free energy of separation from the sorbent (Δ g 0 , s e p ), the sensible heat needed to reach the desorption temperature, and loading optimization to avoid thermodynamic pinching effects. The Δ g 0 , s e p is an invariant of the system, so only its value at reference conditions is required and it is independent of the desorption temperature or the heat of evaporation of a liquid solvent. A baseline is established using the Δ g 0 , s e p as well as the equivalent work for a well-established amine process. In all cases the energy requirements are found to be well above the minimum thermodynamic values and those of conventional liquid absorption. Higher-capacity solid sorbents and challenging improvements on heat recovery will be needed to close the gap. [ABSTRACT FROM AUTHOR]

• A cost-efficient CCS operation cannot be realized without a CO 2 pipeline network. • The paper presents a framework to study different scenarios of a future CO 2 network. • The model uses several geospatial datasets and a dedicated optimization scheme. • The costs of the investigated scenarios range between 1.3 and 3 billion EUR. • The model is flexible and can be used for investigating other scenarios and regions. Carbon capture and storage will be necessary for some industries to reach carbon neutrality. One of the main associated challenges is the design of the network linking the CO 2 sources to the storage sites. Establishing a CO 2 network can be impacted by many uncertainties such as CO 2 amounts, pipeline routes and the locations of emitters and carbon sinks. We present a framework to investigate different scenarios of a future CO 2 network in Germany. The analyses compare the routes and associated costs of different scenarios. The developed model uses several geospatial datasets and an optimization scheme to yield realistic and cost-efficient outcomes. Parameters such as population density and existing infrastructure are integrated to calculate potential routes, which are then used as an input for the developed heuristic model to determine the optimum network. The derived framework is flexible and can be used for investigating other scenarios, regions and settings. The results show that the different scenarios have a profound impact on the optimal layout and costs. The investment costs of the investigated scenarios range between 1.3 and 3 billion EUR. The outcomes are important for academia, industry and policymaking for the ongoing discussions regarding the development of carbon infrastructure. [ABSTRACT FROM AUTHOR]

• Marginal abatement cost curves for CO 2 capture from Swedish industrial and power plants. • Hybrid cost estimation method based on contingency factors and learning rates is applied. • With a first-of-a-kind contingency of 200 %, only 17 projects reach costs of <300 €/t. • Learning rates of 12 % can reduce costs to Nth-of-a-kind levels within 30 projects. • Carbon utilization occurs among early movers and might limit the potential for BECCS. The deployment of CO 2 capture technologies presents opportunities to store fossil fuel emissions from industries and power generation (CCS) and to enable carbon utilization (CCU). However, the costs for early CCS projects are high, and this is a challenge in terms of their economic viability, requiring a strong climate policy with high carbon prices for implementation. This work details a techno-economic assessment of the cost of carbon capture based on a hybrid method and individual project approach, using first-of-a-kind contingency factors and learning rates to study the evolution of carbon capture costs as installed capacity increases over time. The work is based on a case study of 147 Swedish industrial and combined heat and power plants (total of 176 stacks). The results are presented as marginal abatement cost curves, with consideration of early mover CCS projects and learning rates. Deployment scenarios are also presented that take into account an expected increase in the CO 2 price. The findings indicate that when accounting for first-of-a-kind contingencies (100 % and 200 % increases in Nth-of-a-kind costs), 90 and 17 projects, respectively, of the total 176 emission sources studied have specific CO 2 costs of <300 €/t. However, high learning rates (12 %) can reduce the capture costs from first-of-a-kind to Nth-of-a-kind levels within some 30 project installations (100 % contingency). With lower learning rates (3 %), the first-of-a-kind costs are reduced by 10 %–20 %. With the expected increase in CO 2 prices, a peak in carbon capture deployment is observed around Year 2035, at a carbon price of 200 €/t. [ABSTRACT FROM AUTHOR]

• The decarbonisation-PSA process was proposed and investigated from lab to industrial test. • The CO 2 from PSA system emission decreased efficiently. • The CO 2 desorption pressure was enhanced from 0.03 to 0.15 MPa. • The hydrogen recovery rate increased 9 %. • The coupled process was applied industrially for the first time and economic feasibility was verified. The petrochemical industry has a significant demand for high-purity hydrogen. It primarily obtained from the H 2 purification unit by using pressure swing adsorption (PSA) technology to recover H 2 from medium-temperature shifting gas (MTSG). The the coupled wet CO 2 separation-PSA process was introduced in this work, aiming to capture CO 2 from MTSG while simultaneously increasing the H 2 recovery rate. To enhance the desorption pressure of CO 2 separation unit in the coupled process to facilitate the storage or utilization of the captured CO 2 , firstly, a rigorous thermodynamic study was carried out to provide a theoretical basis for the development of an improved CO 2 solvent. Subsequently, a pilot-scale test was executed to validate the theoretical findings. Finally, the patented coupled process was implemented at an industrial scale for the first time. The results showed that the capacity of PSA unit for H 2 purification increased from 6800 to 12,000 tons per year and the H 2 recovery rate increased from 84.6 % to 93.6 %; the CO 2 desorption pressure increased from about 0.03 MPa (traditional Benfield process) to 0.15 MPa, which reduced the energy consumption of CO 2 compression, and the total average annual economic benefits increased by US $ 15.55 million. [ABSTRACT FROM AUTHOR]

• The reactivity of basalt from Poland in CO 2 -water-basalt system was carried out. • An experiment on geochemical reactor was carried out for 65 days at 293 K and 0.43 MPa. • Partial dissolution and conversion of minerals was achieved. • Tight intrapore transport pathways have been clogged with secondary minerals. • A transformation of the macroporosity and morphology of the sample was achieved. The aim of the work was to identify the basic structural properties of basalts from the Central European Volcanic Province in Poland in the context of assessing the possibility of permanent CO 2 storage. The research was carried out on rock samples from three Polish basalt mines. An experiment on the reactivity of minerals contained in basalt was carried out in the original geochemical reactor. In an isolated system with a capacity of 100 cm3, proper analyzes of mineral carbonation were carried out for 65 days at a temperature of 293 K and a pressure of 0.43 MP. The pressure, pH and temperature of the process were recorded. The mechanism of structural changes that occurred in pores of different diameters was determined. SEM microscopic analyzes showed a transformation of the macroporosity and morphology of the sample. The formation of new voids and transport channels was observed, which resulted from the partial dissolution and conversion of minerals. At the same time, the pore surface area in the transitional pores and finest micropores has been reduced, indicating that the surface area of these pores have been overbuilt and the tight intrapore transport pathways have been clogged. The gravimetric measurements of the sorption capacity of basalt in relation to gaseous CO 2 were also conducted. After the mineral carbonation process, the efficiency of CO 2 accumulation decreased, which confirmed that the previously free pore space had been filled. Comprehensive scanning, structural and sorption studies confirmed the migration and multi-track transformation of minerals from basalt. [ABSTRACT FROM AUTHOR]

• The maximum pressure-limited global storage achievable after thirty years of continuous injection is 3640 GtCO 2 (121 GtCO 2 yr-1), increasing to 5630 GtCO 2 (70 GtCO 2 yr-1) at the end of the century. • Applying simplified physics models to estimate injectivity limited storage resources and rates allows for a self-consistent estimate of storage resources across the globe, resolved at the scale of geological basins, and including areas where no resource assessments have yet been carried out. • To achieve the global storage injection rates implied by scaleup trajectories included in the IPCC sixth assessment Report, injectivity limitations mean that deployment will have to expand beyond the ten countries with the most active CCS development today. Limiting global warming to a 2 °C rise may require large-scale deployment of carbon capture and storage (CCS). Due to the key role CCS plays in integrated assessment models of climate change mitigation, it is important that fundamental physical constraints are accounted for. We produce a global estimate of CO 2 storage resource that accounts for pressure-limits within basin-scale reservoir systems. We use a dynamic physics model of reservoir pressurisation that is sufficiently simple to be incorporated into energy systems models. Our estimates address regionally inconsistent methodologies and the general lack of consideration for pressure limitations in global storage resource estimates. We estimate a maximum pressure-limited resource base and explore scenarios with different injection patterns, and scenarios where the extent of CCS deployment is limited by the history of regional hydrocarbon exploration and the readiness of countries for deployment. The maximum pressure-limited global storage achievable after thirty years of injection is 3640GtCO 2 (121GtCO 2 yr-1), increasing to 5630GtCO 2 (70 GtCO 2 yr-1) at the end of the century. These represent an update to volumetric-based estimates that suggest in excess of 10,000Gt of storage resource available. When CCS deployment is limited to the top ten countries ranked by the GCCSI Storage Readiness Index, our maximum storage estimate decreases to 780GtCO 2 (26GtCO 2 yr-1) at the mid-century and 1177GtCO 2 (15GtCO 2 yr-1) at the end of the century. These latter results fall within the range of projected deployment by the IPCC and IEA and suggest that reservoir pressurisation will limit CCS deployment if development does not rapidly expand beyond the current implementation. [ABSTRACT FROM AUTHOR]

• The absorption-desorption performance of three blended amine absorbents was tested;. • The corrosion experiments were carried out and the corrosion behavior was analyzed;. • The kinetic performance of CO 2 absorption was investigated by a wet wall tower;. • HEP-AEEA/AEP/PZ aqueous solutions show better performances for CO 2 capture. The chemical absorption method using amine-based aqueous solutions as absorbents is considered a critical technology in the mitigation of CO 2 emissions. However, the trade-off between absorption performance and energy consumption presents a significant challenge for large-scale industrial applications. In this study, we propose using N-(2-hydroxyethyl)ethylenediamine (AEEA), 1-(2-amino Ethyl)piperazine (AEP) and piperazine (PZ) to regulate the CO 2 capture characteristics of 1-(2-hydroxyethyl)piperidine (HEP) aqueous solution. We found that the addition of promoter AEEA/AEP/PZ increases the CO 2 absorption and desorption performance of HEP aqueous solution. We established the CO 2 capture mechanism, which involves the generation of HEPH+, carbamate, and bicarbonate during the absorption of CO 2. During the desorption process, the bicarbonate can be decomposed, while the carbamate remains in the solution. Furthermore, we obtained data on the kinetics and corrosion characteristics of the blended absorbents. The absorption resistance of the three blended amine aqueous solutions is concentrated on the gas film, accounting for approximately 77 %. The corrosion rate of blended amine-enriched solutions on 20# carbon steel decreases with the increasing mass fraction of promoters or CO 2 loading. SEM-EDS analysis revealed the presence of a dense FeCO 3 oxide film on the surface of 20# carbon steel, which protects the carbon steel sheet from further corrosion. Overall, the proposed absorbents indicated a promising potential in the CO 2 capture applications. [ABSTRACT FROM AUTHOR]

• Carbon mineralization in mafic and ultramafic formations offers an attractive CO2 storage option. • Several key technical factors affecting the success, scale, and cost of in-situ carbon mineralization projects are discussed. • Overview of pilot tests, projects, and associated costs is provided. Carbon mineralisation in underground mafic and ultramafic formations, known as in-situ carbon mineralisation, has emerged as an attractive technology for permanent CO 2 storage. Despite its potential, this method has received limited attention compared to conventional CO 2 storage in sedimentary formations. However, increasing interest from countries and companies in utilising this approach to permanently store CO 2 via carbon mineralisation has grown in recent years as part of the wider carbon capture and storage expansion seen globally. This review paper aims to provide an in-depth overview of in-situ carbon mineralisation technology. The paper covers key factors crucial for successful implementation, including water consumption, CO 2 injection rate, risk of CO 2 leakage, injectivity, fracture characterisation, pressure management and induced seismicity, thermal effects, surface area of minerals, groundwater contamination, injection strategy, monitoring of confinement, and reservoir modelling. The paper also discusses pilot tests and projects, highlighting their outcomes. Furthermore, it discusses the costs associated with in-situ carbon mineralisation and provides a case study. The primary objective of this paper is to increase awareness and understanding of this relatively new technology within the carbon capture and storage industry. By shedding light on the benefits and challenges of carbon mineralisation in mafic and ultramafic formations, this review aims to encourage further research, development, and adoption of this promising approach for CO 2 emissions reduction and permanent CO 2 storage. [ABSTRACT FROM AUTHOR]

• This review explores the essential components required to implement an integrated CCS system with a specific focus on establishing a CCS value chain. • This review covers cost estimation and optimization of CO 2 pipeline infrastructure. • In addition, this review focuses on flow assurance in CO 2 pipeline, and corrosion issue. Carbon capture and storage (CCS) is a promising technology for mitigating greenhouse gas emissions and achieving carbon neutrality. In the CCS value chain, CO 2 pipeline transportation is essential in linking emission sources to storage sites. For instance, the design of CCS transportation requires the consideration of factors such as distance, CO 2 vol, and construction costs while addressing phase changes, corrosion, and optimizing the pipeline network to ensure cost efficiency. Furthermore, involving the meticulous consideration of operational conditions and impurity effects, flow assurance is vital to ensure the safe and efficient transportation of CO 2 through pipelines. Advancements in network optimization techniques and sophisticated modeling have contributed significantly to the realization of CCS projects worldwide. This review investigates essential aspects and relevant studies for effective CO 2 pipeline transportation within a comprehensive framework of CCS infrastructure and its life cycle. State-of-the-art studies have been extensively reviewed and, where necessary, tabulated and plotted for summarization. Via comprehensively understanding and proactively addressing the inherent challenges and considerations associated with CCS transportation, foundation for effective CCS implementation can be laid. [ABSTRACT FROM AUTHOR]

• CO 2 and O 2 MNBs exhibit low ζ-potentials at low pH from laboratory experiments. • A resonant mass spectrometer is effective for measuring the density of CO 2 MNBs. • The resistivity survey efficiently identified the migration region of CO 2 MNB water. In light of the application of CO 2 micro-nanobubbles (MNBs) in distributed carbon dioxide capture and storage (CCS), a series of experiments were conducted to investigate the stability of CO 2 MNBs. Prior to the in-situ assessments, foundational laboratory experiments were performed to evaluate the stability of the MNBs. Subsequently, a small-scale in-situ CO 2 MNB injection test was conducted to measure the CO 2 MNB density in the extraction well. The bubble density was measured using a resonance mass spectrometer, which effectively discerns bubbles from solid particles. Furthermore, the behavior of the injected CO 2 MNB water was monitored through electric resistivity surveys. The findings revealed that CO 2 MNBs and O 2 MNBs exhibit low ζ-potentials at low pH values. Regarding bubble density, the CO 2 MNB remained relatively stable at a pH of 4, proximate to the point of supersaturation. As time elapsed following injection, the bubble density in the extraction wells of the in-situ CO 2 MNB water injection experiments steadily increased, implying the replacement of groundwater in the aquifer by injected CO 2 MNB. The resistivity survey effectively delineated the migration area of the CO 2 MNB water, indicating that CO 2 MNBs could persist in the aquifer even up to one day post-injection. Laboratory measurements of ζ-potential and bubble density further corroborate the complete displacement of water in the aquifer by CO 2 MNB water, leading to a reduction in porewater pH and ultimately facilitating the stable retention of CO 2 MNBs. [ABSTRACT FROM AUTHOR]

• Stacked Columbia River basalt reservoirs can store up to 40 gigatons of CO 2. • United States department of energy method was adopted to estimate the basalt storage resource. • Basalt provides alternative mineralization storage option for stranded emission sources. This work presents a detailed supercritical CO 2 storage resource estimation for the stacked basalt reservoirs in the Grande Ronde Basalt of the Columbia River Basalt Group in eastern Washington and Oregon. The assessment aims to derisk the commercialization potential of geologic carbon storage in basalt by leveraging both structural and mineralization trapping of CO 2 in basalt. The structural closures formed by anticlinal ridges and synclinal valleys in Yakima Fold Belt are excellent physical traps to accommodate injected supercritical CO 2. Rigorous hydraulic testing, well logs and simulation results from the Wallula Basalt Pilot #1 well showed the occurrence of 17 suitable permeable injection zones (up to 2,496 mD) intercalated with dense seals (∼2.6E-10 mD) in the Grand Ronde Basalt. In addition, geochemical studies showed fast reactions between supercritical CO 2 and dissolved basalt minerals to form stable carbonates. Our calculation indicates up to 40 gigatons (P90) of mineralization storage resources exist in the Grande Ronde Basalt reservoirs. [ABSTRACT FROM AUTHOR]

• The jet structure of pipe leakage under various initial conditions and orifice diameters are obtained. • The leakage near-field parameters under various initial conditions and orifice diameters are obtained. • Experiments reveal the dominant cause of near-field characteristics of pipeline leakage. • Experiments provides input condition parameters for far-field leakage simulations. Accidental leakage poses a significant safety concern for carbon capture, utilization, and storage (CCUS) projects. Understanding the near-field characteristics of leakage is essential for dispersion studies, safety distance calculations, and risk assessment of emergency response to a pipeline leakage. This paper presents a small-scale CO 2 pipeline leakage experiment designed to investigate the transient characteristics of near-field parameters, including temperature, pressure, and jet structure. The study also analyzes the effects of factors such as initial pressure, initial temperature, and leakage orifice diameter on the transient characteristics of the near-field. The experimental results demonstrate that lower initial temperatures lead to higher near-field pressure peaks, while larger orifice diameters result in larger near-field pressure peaks. Furthermore, a larger hole diameter combined with a lower initial temperature and higher initial pressure leads to the negative pressure region in the near-field being farther away from the leakage opening. In the liquid state, the near-field temperature is lower compared to the gaseous state due to the strong liquid-gas flash evaporation. When different orifice diameters are used for depressurization, larger diameters cause a more significant drop in near-field temperature. The study also reveals that the effect of initial temperature on the jet structure is less significant compared to the effect of initial pressure. The primary objective of the experiment was to collect near-field leakage data and analyze the characteristics of near-field leakage. It is hoped that this work will contribute to the improvement of research models that assess the consequences of potential high-pressure pipeline rupture scenarios. [ABSTRACT FROM AUTHOR]

• Anhydrite-rich rock has the potential to serve as natural carbon sinks through the mineralization of CO 2. • Anhydrite undergoes mineral transformation upon exposure to supercritical CO 2 -saturated brine in the presence of SrCl 2. • Carbonation products include calcite, dolomite, magnesite, strontianite, and celestite. • The extent of CO 2 mineralization is influenced by brine composition. • Carbonation reactions are driven by both the coupled dissolution-precipitation and diffusion mechanisms. The utilization of subsurface geologic media for carbon capture and storage through mineralization has been recognized as a reliable approach. However, less attention has been given to anhydrite rock type for CO 2 mineralization and storage. Anhydrite-rich rock formations, commonly found in various geological settings, have the potential to serve as natural carbon sinks through the mineralization of CO 2. Therefore, this study aims to investigate the mechanisms and potential of anhydrite-CO 2 -brine interactions for carbon storage. The experimental approach involved exposing anhydrite-rich rock to supercritical CO 2 -brine environments under varying conditions of fluid composition. Mineral transformation of an outcrop anhydrite-rich rock sample in static reactor under subsurface conditions of elevated temperature (60 °C) and pressure (104 bar), in the absence and the presence of SrCl 2 was conduct for a one-month period. Mineralogical and geochemical analyses, including, solution analyses, X-ray fluorescence, X-ray diffraction, micro-computed tomography, and mechanical properties were conducted to examine the changes in the composition and rock structure resulting from the interactions. The experimental reactions revealed that anhydrite undergoes mineral transformation upon exposure to supercritical CO 2 -saturated brine to form stable minerals including calcite, dolomite, magnesite, and strontianite, which contributes to the potential for long-term storage of CO 2 in the subsurface geologic media. The efficiency and extent of carbon mineralization were found to be influenced by brine composition. These findings contribute to the understanding of the potential of these formations for carbon storage, opening avenues for further research and the development of effective carbon capture and storage strategies. [ABSTRACT FROM AUTHOR]

• Investigates the dynamic interactions between technological, economic and societal aspects, with the aim of clarifying enablers for and barriers to the implementation of industrial CCS in the North Sea Port industrial cluster. • Brings together stakeholders from industry, government and society to collaboratively build a qualitative model of the system dynamics of the implementation of industrial CCS in the North Sea Port industrial. • Demonstrates the interdependency of societal and techno-economic aspects in the implementation of CCS. • Shows the need for transparent public engagements, and decisiveness and commitment from government and industry to successfully and responsibly implement CCS. Carbon dioxide capture and storage (CCS) is considered an option for energy-intensive industry to reduce its greenhouse gas emissions. Although it is well known that CCS faces technological, economic and societal challenges, how these challenges interact in a real-life industry has not yet been investigated collectively in a place-specific context. This study fills that gap by looking at the dynamic interactions between technological, economic and societal aspects, with the aim of clarifying enablers for and barriers to the implementation of industrial CCS in the North Sea Port industrial cluster, and identifying a course of action. The analysis was based on literature, interviews and group model building. By using group model building, expert stakeholders were brought together from industry, government and environmental non-governmental organizations. The participants built a qualitative model of the system dynamics of the implementation of industrial CCS in the North Sea Port industrial cluster jointly and on the spot. Enablers and barriers, such as costs, government's decisiveness and public support, are strongly interrelated. Public support plays a key role in multiple feedback loops in the system of industrial CCS implementation. The interdependence of societal and techno-economical elements needs to be acknowledged and responded to. There is need for transparent public engagement to build public support for CCS, and decisiveness and commitment from industry and government to transform that public support into successful and responsible CCS implementation. [ABSTRACT FROM AUTHOR]

• A CCS project business case at operational cement plant is examined. • Uncertainties impact in viability and profitability project using Monte-Carlo method. • Three different sources for generating the steam: electrical boiler, gas boiler and heat pump. • CO 2 prices are not high enough to reach breakeven, additional economic incentives are crucial. • Shift in the current business models in cement companies is necessary. The implementation of Carbon Capture and Storage-CCS has been projected to deliver substantial reductions to achieve the Net Zero scenario by 2050 and it is regarded a solution particularly relevant in decarbonizing heavy industries like cement production. However, historical challenges, partly caused by the absence of a viable business case, have hindered widespread adoption. Addressing the uncertainties surrounding the business case is crucial to identifying mechanisms that can expedite CCS deployment in these sectors. This study presents an analysis of a conceptual business case of a hypothetical CCS project at an operational cement plant in Europe, highlighting the impact of various uncertainties on its viability. It provides insights into potential project profitability under the influence of CO 2 prices and two types of subsidy schemes to achieve breakeven conditions based on the chosen assumptions. The findings indicate that anticipated CO 2 prices alone do not expedite the deployment of CCS, necessitating additional economic incentives or revenue streams to establish a financially viable business case. This could potentially be realized by transforming the business model of cement companies, including the creation of a market for CO 2 -neutral cement and advocating for green public procurement in construction projects. [ABSTRACT FROM AUTHOR]