Carbon capture and storage (CCS) is recognized as an important technology for reducing greenhouse gas emissions and achieving climate targets, yet some segments of society express public opposition. Public opposition, even when expressed by minority groups, has at times influenced CCS project outcomes. Opposition extends beyond technical risk concerns, including emotional, symbolic, and territorial dimensions. This study examines how such opposition was constructed through protest materials, social media content, and press articles related to a specific CCS project. A mixed-methods design combined sentiment analysis using a natural language processing (NLP) model with qualitative content analysis. Because the corpus was deliberately sampled from oppositional channels, these sentiment scores characterize how opposition is expressed rather than the balance of public opinion at large. Within this corpus, opposition was articulated largely through negative sentiment (mean sentiment -0.44), particularly in materials from environmental NGOs and labor unions, with recurring concerns including seismic risk, proximity, institutional distrust, and perceived territorial injustice. On the qualitative side, protesters frequently employed emotionally charged metaphors (e.g., “ticking bomb”, “waste”) and comparisons to other CCS projects, reframing the technology as an imposition rather than a climate solution. Nonetheless, the dataset also captured neutral and occasionally supportive tones, especially in citizen and press discourse, indicating that while opposition dominated, public responses were not monolithic. These findings contribute to a more nuanced understanding of CCS acceptance by highlighting the emotional, symbolic, and communicative dynamics of opposition. The study also demonstrates the value of sentiment analysis for capturing discursive opposition in contested projects. Moreover, the results underline that the social acceptance of CCS is shaped as much by identity, symbolism, and public discourse as by technical and regulatory considerations.
Alkali activation significantly enhances the carbonation reactivity of coal-based solid waste (CBSW) with CO2, and exploring its carbon sequestration characteristics, microstructures and reaction mechanisms is critical for improving carbonation efficiency. This study prepared foamed CBSW samples from coal gangue and fly ash, using quicklime as the alkali activator. NMR, FTIR, XRD, SEM-EDS, and TGA were employed to investigate the evolution of the microscopic pore structure, carbon-fixing component variations, carbonation absorption characteristics, and carbon sequestration performance under different activator dosages, and to summarize the underlying micro-mechanisms. Results showed that alkali activation effectively modified CBSW: carbonation curing formed a more complex pore structure via product filling, reducing the T2 distribution, the porosity and the large pore throats. Higher activator dosage strengthened the O–C–O and C–S–H absorption peaks, increased the CaCO3 characteristic peaks and weakened the Ca(OH)2 ones. The samples’ thermogravimetric decomposition had three stages, with the third stage corresponding to carbonation product decomposition. Notably, within the tested range, the highest activator dosage of 30% exhibited the maximum carbon sequestration capacity in this study: a 19.73% CO2 mass fraction, a 245.87 g/kg CO2 absorption capacity, and an 18.36% carbon sequestration rate. The main carbon sequestration products were CaCO3 and C–S–H gel, with calcite as the dominant crystalline mineral, along with minor amounts of dawsonite and siderite. This study provides a valuable reference for bulk CBSW utilization and efficient CO2 sequestration, supporting the dual-carbon goals.
Balancing mineral trapping with pore-network preservation remains a key challenge for CO2 storage in deep saline sandstones. Here, we propose a precipitation-provenance framework to distinguish carbonate recycling from silicate- and clay-fed net carbonate formation. Two tight sandstones, a calcite-cemented red sandstone (RS1) and a plagioclase/chlorite-rich grey sandstone (GS1), were reacted with scCO2-brine at 120°C and 30 MPa. Image-registered ESEM-MapsMin automated mineralogy, CT-resolved 3D pore-network analysis, and ICP-OES brine chemistry were integrated to track coupled dissolution-precipitation from grain to core scale. RS1 followed a carbonate-buffered recycling pathway, where calcite dissolution-reprecipitation and feldspar corrosion increased CT porosity from ∼2.0% to ∼5.5% but produced limited net mineral trapping. In contrast, GS1 showed silicate-fed carbonate formation: plagioclase and chlorite supplied Ca-Mg-Fe, increasing MapsMin-derived calcite abundance from near-zero to ∼13 wt%, while pore-wall coatings and local throat restriction moderated pore growth. We further distinguish likely in situ pore-wall carbonates from depressurization-related carbonates and drying-derived halite to avoid overestimating reservoir-condition trapping. Together, these results provide mechanistic criteria for screening sandstone storage formations and for designing pressure-management strategies that maximize mineral trapping while limiting adverse pore-network feedbacks.
CO2 storage operations in fractured sandstone reservoirs are challenging as they may result in high reservoir pressure buildup, caprock hydraulic fracturing, or fault slip reactivation. We assess CO2 injection capacity in fractured tight saline aquifer of the Lower Paleozoic Potsdam sandstone in the Bécancour fault block, St. Lawrence Platform at a depth of ∼1.2 km. Static storage capacity evaluation and 3D dynamic reservoir simulations of CO2 injection in a vertical and a horizontal well are conducted. The fractured reservoir model is calibrated by performing a history match based on brine production. CO2 is predominantly stored in the gas phase rather than dissolved in water, with a greater amount residing in the matrix than migrating through fractures. The pressure front propagates through the fractured reservoir much faster and farther than the CO2 plume, elevating geomechanical and well integrity risks at a greater distance from the injection site area. In fractured tight reservoirs with pressure-limited capacity, CO2 single-well accessible storage potential and actual injection rate are strongly controlled by pore volume, bottomhole pressure buildup, and well design. Utilization of horizontal, rather than vertical, wells in fractured tight reservoirs is estimated to be preferable for CO2 injection as it helps to increase reservoir contact, maximize intersection with vertical fractures, reduce bottomhole pressure and vertical CO2 plume propagation, lower the risk of caprock leakage and increase storage capacity. A grid-sensitivity test indicates that dynamic properties, such as pressure and saturation, depend on grid cell size and are more accurately estimated in fine resolution grids.
Methane (CH4) and carbon dioxide (CO2) are both significant greenhouse gases (GHGs). Due to the sources of capture and economic costs, the presence of CH4 impurities is inevitable. However, there is insufficient experimental research on the leakage risks during the transport of CO2 mixed with CH4. In this study, a 258 m pipeline was equipped with a DN40 bypass and 11 electric valves to simultaneously inject CH4 impurities, simulating real conditions of CO2 pipelines containing CH4. Furthermore, the velocity mechanism within the diffusion region was explained microscopically through gas mixing equations. The results indicate that the evolution of the visible cloud is significantly related to the orifice size, following a negative exponential relationship. However, for both orifices, the high-risk asphyxiation zone for CO2 was within the first 45 m, with the smaller orifice posing a greater asphyxiation hazard. Analysis of diffusion data and mixture properties calculations revealed that the velocity and diffusion of the CH4 plume exceeded that of CO2, with CH4 concentrating at the front of the mixed gas stream. As such, CH4 concentration can serve as a reliable indicator for detecting pipeline leaks. In severe cases of pipeline overpressure rupture, sparks from metal debris collisions could lead to potential fires or explosions. This study investigates the safety of transporting CO2 containing CH4 impurities in pipelines, highlighting the various safety risks posed by CH4 impurities. Comprehensive analysis of the fundamental data is conducted, providing scientific evidence and engineering guidance to ensure the safety of pipelines in the CCUS process.
Regional assessment of storage resources have historically relied largely on volumetric methods (static capacity). These methods are similar to petroleum resource assessments and straightforward to apply, but they implicitly assume unlimited brine displacement to accommodate the injected CO2. Bump and Hovorka (2024) pointed out that no reservoir extends forever, that geologic basins are fundamentally closed volumes. They argued that regional storage resources are pressure-limited and illustrated their proposed methods by application to the Texas coastal Miocene. Although that is clearly a subset of the lager Gulf of Mexico basin, they argued that it was a useful example and that the boundaries might be closed by sealing regional growth faults. They calculated a storage resource of 20.3Gt, a sharp reduction from the previous figure of 125Gt derived from volumetric methods.But what if those regional growth faults did not create a regionally closed boundary? There is ∼100 km of laterally equivalent reservoir between the coastal Miocene study area and Miocene outcrop. The actual boundary conditions for the Texas coastal Miocene are unclear, but it is a well-studied area that makes a useful example. In the spirit of exploration and quick answers from minimal data, this study uses another analytical solution to look at the effect of adding the up-dip Miocene as a pressure dissipation zone. In the base case, we find that it increases the coastal Miocene storage resource from 20.3Gt to 36Gt, simply by allow displaced brines to migrate out of the coastal injection area. Migration wanes with distance, such that the effect at outcrop is to lift the salinity contours by 3–4 m, consistent with previous work.Whatever the actual boundary conditions for the Texas coastal Miocene, we believe that this work has broad application in the evaluation of regional storage resources. Like the coastal Miocene, many potential storage areas have reservoirs that continue beyond the assessment boundaries—into adjacent leases, underneath cities, or into similarly inaccessible areas. Although they may be off limits to injection, these adjacent reservoirs form important dissipation zones that may offer substantial additional storage resources even without accepting any CO2. The method presented here offers a quick-look approach to analyzing their impact.
Direct Air Capture (DAC) is a promising negative emission technology with the potential to remove excess CO2 from the atmosphere. The levelized cost of solid sorbent (S-DAC) and liquid solvent DAC (L-DAC) is highly region-specific, driven by variability in weather conditions and renewable energy potential. This necessitates a holistic, global assessment that combines these two technologies with the highest technology readiness levels to identify cost-optimal locations for DAC deployment. Here, we identified optimal locations for S-DAC and L-DAC using an hourly cost optimization model that incorporates weather-driven performance and region-specific solar, wind, and geothermal energy resources under fully electric and hybrid energy configurations, where hybrid systems combine electric and direct renewable heat. We show that DAC deployment is cost-optimal in regions combining low renewable energy costs with favorable weather conditions, with S-DAC favored in Australia, Iceland, Mexico, and parts of Asia, and L-DAC in much of South America and Sub-Saharan Africa. The energy configuration strongly influences costs, with hybrid systems resulting in lower global levelized costs of DAC in 2050 ranging from 160 to 1720 €/tCO2, with a median of 271 €/tCO2. Our study further reveals that DAC can achieve a deployment level of 2 GtCO2/a at costs below 195 €/tCO2 in cost-optimal regions. At the same time, substantial uncertainty remains in future cost estimates, with global median values ranging from 144 to 392 €/tCO2 depending on underlying techno-economic assumptions. These results emphasize the importance of holistic, region-specific assessment to guide strategic and cost-effective global DAC deployment, aligned with the cost-efficiency principles in Article 6 of the Paris Agreement.
Adsorption-based Direct Air Carbon Capture and Storage (DACCS) is a promising carbon dioxide removal technology, albeit with high electricity demand. Demand-side management (DSM), i.e., shifting electricity demand to times of low electricity prices, can reduce electricity costs. In Postweiler et al. (2025), we demonstrated the efficacy of DSM for DACCS by solving a dynamic optimization problem via the gradient-free optimization method particle-swarm optimization (PSO). However, PSO is computationally very demanding and thus not real-time capable, severely limiting the resolution of time-continuous controls like flow rates. Herein, we implement real-time capable economic nonlinear model predictive control (eNMPC). We first modify the process model to obtain nonsmooth differential–algebraic equations enabling direct single shooting using a smoothing approach. We demonstrate our method in an eNMPC case study, showing real-time applicability on a single core of a standard CPU. We study the impact of the resolution and the choice of the controls, the foresight in the eNMPC setup, and the optimality tolerance on the computational performance. We choose a trade-off to compare the optimal profit achieved with the literature. We conclude that gradient-based dynamic optimization enables real-time applicability as well as more profitable operation, paving the way for large-scale DACCS employment.
Semi-airborne controlled source electromagnetic (CSEM) is a potential method for low impact monitoring of conductivity changes associated with subsurface CO₂ injection into saline aquifers. In this study, we use data from a 2023 CSEM survey at the Kemper CarbonSAFE site in Mississippi, where grounded dipole transmitters and a helicopter towed SQUID magnetometer were used. Our goal is to develop a baseline 3D conductivity model and evaluate the survey’s ability to detect changes associated with potential CO₂ migration.We invert the dataset using l-BFGS-B optimization with β-cooling, an L₁ norm data misfit, and model regularization that enforces smoothness relative to a spatially varying reference model. Forward modeling and adjoint gradients are computed using EMG3D. The reference model is built from a combination of petrophysical analysis of well logs from three boreholes, and simple boundary constrained parametric inversion. Depth weighting is applied as a gradient preconditioner to improve convergence and encourage deeper model updates, and sensitivity weighting helps stabilize updates near transmitter lines.To assess monitoring feasibility, we simulate idealized CO₂ plumes that modify the baseline model and compare their predicted EM responses to residuals from the baseline inversion. Deep plumes in the Washita-Fredericksburg Formation remain undetectable under current noise levels, but leaks into shallower formations produce coherent signal changes that exceed local data residuals. These results demonstrate that the current acquisition and processing strategy could support time lapse detection of shallow CO₂ migration, while also highlighting areas for refinement in future deployments.
Carbon dioxide (CO2) hydrates offer unexplored avenues for applications like long-term carbon sequestration, gas separation and desalination. CO2 hydrates are ice-like solids of water and CO2 that form near freezing temperatures and moderate pressures. Recent work from this group reported ultrafast formation of CO2 hydrates in a bubble column reactor using magnesium as a passive nucleation promoter. While our past studies utilized pure CO2, we presently study hydrate formation from binary mixtures of CO2 and nitrogen at three CO2 concentrations (15, 50 and 90 mol%). We report sequestration rates as high as 1200 g h−1 L−1 MPa−1 with 90% CO2, which is within 6% of those achieved with pure CO2. Such high formation rates with impure CO2 vastly improve techno-economics since purification of CO2 is energy and cost intensive. Significantly, we achieve high rates with synthetic ocean water, noting that salt content has an inhibiting effect on hydrate formation. This eliminates the need for desalination further improving techno-economics. Our use of sub-millimetric bubbles for sparging increases the density of hydrates formed and the conversion of CO2 gas into hydrate. Importantly, near-instantaneous (less than 1 second) nucleation occurred with 50 and 90% CO2 concentrations. Additionally, we use machine learning (ML) to train and evaluate 2 algorithms (Random Forest, RF, and Extreme Gradient Boosting, XGBoost) to predict the hydrate CO2 composition based on feed CO2 composition, pressure, and temperature. XGBoost outperforms RF with an overall coefficient of determination (R2) of 99.5%.
Climate change poses a major challenge that requires urgent actions to counteract the harmful effects of greenhouse gas emissions, particularly CO2. A comprehensive analysis and optimization of a Cryogenic Carbon Capture (CCC) process based on CO2 desublimation is performed to enhance the recovery and purity of CO2 captured from flue gas to meet the CO2 specifications for transport, storage, or utilization. The proposed system, modeled in Aspen Plus and optimized using a Probabilistic Surrogate-Assisted Framework (PSAF), achieves high CO2 recovery (up to 99%) and purity (>99.99 mol%) while minimizing electrical energy consumption. The study investigates the impact of key process variables, i.e., flue gas CO2 concentration, contact liquid temperature and flow rate, and product CO2 state (liquid or gaseous) on the energy and economic performance of the CCC process. The results show that electrical consumption ranges between 330 and 435 kWh/tCO2, depending on flue gas composition and recovery targets. Economic analysis reveals capture costs between 70 and 120 €/tCO2 (at an electricity price of 100 €/MWh without carbon taxes) with significant sensitivity to electricity prices and carbon taxes, while environmental assessment underscores the importance of renewable electricity sources in maximizing CO2 avoided emissions. Overall, this work confirms the technical viability, economic competitiveness, and environmental potential of CCC based on desublimation for post-combustion CO2 capture, particularly for medium to high CO2 concentrations in flue gases.
Reducing process CO₂ emissions from lime production is essential for decarbonising one of the most carbon‑intensive industries. This study provides the first comprehensive life cycle assessment (LCA) of indirectly heated calcium carbonate looping (IHCaL) applied to lime plants, evaluating five scenarios: a reference plant, two tail‑end IHCaL configurations, and two fully integrated IHCaL configurations, each fuelled by lignite or solid recovered fuel (SRF). Using ReCiPe 2016 midpoint and endpoint methods and a functional unit of 1 kg of lime, environmental impacts were quantified across 18 categories and assessed using Monte Carlo uncertainty analysis (10,000 iterations).All IHCaL scenarios substantially reduce global warming impact relative to the reference case, with reductions exceeding 80%. SRF‑fuelled systems achieve net‑negative mean global warming impact due to avoided landfill burdens, and tail-end configurations further benefited from electricity export. However, lignite‑fuelled IHCaL scenarios increase freshwater and marine ecotoxicity, freshwater eutrophication, and human carcinogenic toxicity, driven mainly by upstream lignite mining. SRF‑fuelled scenarios avoid these burdens but have higher mineral and fossil resource scarcity impacts related to natural gas use in SRF processing.IHCaL offers a strong route to decarbonisation of lime production, provided fuel supply chains are carefully managed. The findings show SRF as the environmentally preferred fuel and underscore the importance of upstream process optimisation and region‑specific electricity modelling.
Surfactant-assisted CO2 injection has been proposed as a strategy for improving injectivity in geological carbon storage (GCS) by mitigating capillary-controlled flow resistance. In this study, the interfacial behavior of three representative surfactants—an anionic surfactant (SDBS) and two nonionic surfactants (Pluronic L31 and POA-25R2)—was systematically investigated under reservoir-relevant conditions. Critical micelle concentration (CMC), interfacial tension (IFT), and contact angle were evaluated under reservoir conditions, and their combined effects were quantified using the capillary factor. The results demonstrated that surfactant performance under reservoir conditions deviates significantly from observations made under ambient conditions, most notably through a substantial reduction in the CMC. Among the tested surfactants, SDBS exhibited the greatest reduction in IFT, whereas POA-25R2 induced the most pronounced wettability alteration toward intermediate-wet conditions, resulting in the largest reduction in the capillary factor. Quasi-static pore network simulations incorporating these interfacial properties showed that capillary factor reduction lowered capillary entry pressure and increased CO2 saturation under capillary-dominated conditions. Additional analysis at elevated temperature and salinity showed that POA-25R2 retained measurable interfacial activity in 3.5 wt% NaCl brine, although its effectiveness was attenuated at 80°C. These findings underscore the necessity of integrated evaluations of IFT, wettability, and CMC under reservoir conditions and provide a dosage-aware framework for surfactant screening in injectivity-focused GCS applications.
Deep saline aquifers are promising candidates for geological CO2 storage; however, high capillary pressures often restrict the initial CO2 injectivity, particularly in near-wellbore regions. Although surfactant-induced interfacial tension reduction is known to lower capillary resistance, its direct impact on dynamic multiphase flow across various rock fabrics remains poorly quantified. This study investigated the effects of a nonionic surfactant on CO2–brine relative permeability and spatial fluid distribution using a 2D X-ray imaging–integrated core flooding system. To elucidate the influences of rock heterogeneity and flow orientation, primary drainage experiments were conducted under reservoir conditions on three distinct sandstones representing contrasting rock fabrics: homogeneous Berea sandstone, heterogeneous offshore reservoir sandstone (D-1), and vertically cored Otway CRC-2 sandstone. Interfacial property measurements confirmed that the surfactant significantly reduced the capillary factor by lowering the interfacial tension and altering wettability. The dynamic flow results revealed that surfactant pretreatment enhanced CO2 mobility across all samples. In the heterogeneous d-1 sandstone, the surfactant allowed CO2 to invade previously bypassed pore volumes, thereby increasing endpoint CO2 saturation and doubling relative permeability. In the vertically cored CRC-2 sandstone, the surfactant successfully mitigated serial capillary barriers produced by cross-bedding flow. It smoothed the severe localized saturation oscillations observed under baseline and increased endpoint CO2 relative permeability by approximately 2.5 times. These findings demonstrate that the mechanism of surfactant-assisted injectivity enhancement strongly depends on the heterogeneity and anisotropy of reservoir rock, highlighting the potential of targeted near-wellbore surfactant treatments for optimizing commercial-scale CO2 storage operations.
Given the anticipated increase in H2 production and the transition to a low-carbon economy, sustainable CO2 capture methods, such as physical absorption using ionic liquids (ILs), are paramount. This study introduces a new approach to model the novel IL [HEMMIM][CCN3] by incorporating the modified translation-rotation-internal coordinate (TRIC) system for molecular geometry optimization with a COSMO-based/Aspen Plus approach. Conductor-like screening model within density-functional theory (COSMO-DFT) calculations using Amsterdam Modeling Suite (AMS/ADF) software were carried out on the optimized IL ion-pair to compute parameters needed for the conductor-like screening model for real solvents (COSMO-RS) and conductor-like screening model – segment activity coefficient (COSMO-SAC) supporting the process model. Aspen Plus is used to synthesize and model a pre-combustion CO2 capture process to assess the performance of [HEMMIM][CCN3] relative to an established IL [BMMIM][TF2N] via energy, exergy, and economic analysis (3E). At optimized conditions, both ILs achieved a relatively close CO2 recovery rate, with high H2 purity, while the novel IL [HEMMIM][CCN3] showed 57 % less total duty requirements and roughly 80 % lower exergy loss than those for the [BMMIM][TF2N] system, resulting in reduced operating and utility costs by 53 % and 57 %, respectively.
In Carbon dioxide Capture and Storage (CCS), gas-hydrate trap mechanism is attracting attention as an alternative and backup storage method. This method applies CO₂ hydrate formed under low-temperature and high-pressure conditions to contain CO₂ in a geological formation. However, understanding gas chimney structures, which can be a leakage pass through a hydrate stability zone (HSZ), is essential for evaluating hydrate trap potential. Conventional research on gas chimneys has mostly focused on methane gas. The objective of this study is to numerically investigate the mechanism of CO₂ chimney formation using a two-phase flow simulator that considers gas hydrate formation within subsea sediments: how CO₂ chimneys are formed and how the differences in permeability, CO₂ chamber thickness, and salinity affect the formation of chimney structures. The results showed that the structure and formation mechanism of CO₂ chimney differ significantly from that for methane. Dissolution of CO₂ increased the density of water within the assumed cylindrical high-permeability region (HPR), generating a downward current. CO₂ that rose outside the HPR was blocked by hydrate and moved upwards along the side of the HPR towards the seabed. As a result, the CO₂ chimney had a hollow, cylindrical structure.
