Search Results (94)

This study evaluates the technical, design, and economic feasibility of large-scale hydrogen storage in deep water-bearing geological formations (aquifers), presenting it as a scalable solution for seasonal energy storage within the European Union’s decarbonization framework. A techno-economic model was developed for a 1 BCM facility, integrating geomechanical, microbial, and thermodynamic criteria. The results indicate a recoverable hydrogen fraction of 70–85%, with dissolution and microbial conversion losses limited to below 10% under optimized operational regimes. Geochemical and microbiological modelling demonstrated that sulfate-reducing and methanogenic bacterial activity can be reduced by 80–90% through controlled salinity and pH management. The proposed design, incorporating high-permeability sandstone reservoirs (100–300 mD), hydrogen-resistant materials, and fibre-optic monitoring ensures stable containment at 60–100 bar pressure and enables multi-cycle operation with minimal leakage (<0.05% per year). Economically, the baseline Levelized Cost of Hydrogen Storage (LCOHS) for aquifers was found to be ~0.29 EUR/kWh, with potential reductions to ~0.18 EUR/kWh through optimized drilling, modularized compression systems, and microbial mitigation. The lifecycle carbon footprint (0.20–0.36 kg CO₂-eq/kg H₂) is competitive with other geological storage methods, while offering superior scalability and strategic flexibility. Full article

CO₂ circulation between subsurface wells is a promising approach for geothermal energy recovery from deep saline formations originally developed for Carbon Capture and Storage (CCS). This study evaluates the feasibility, operability, and performance of sustained CO₂ flow between an injector and a producer at the Canadian Aquistore site, a location with active CO₂ injection and an established geological model. A high-resolution sector model, derived from a history-matched parent simulation, was used to conduct a comprehensive uncertainty analysis targeting key operational and subsurface variables, including injection and production rates, downhole pressures, completion configurations and near-wellbore effects. All simulation scenarios retained identical initial and boundary conditions to isolate the impact of each variable on system behavior. Performance metrics, including flow rates, pressure gradients, brine inflow, and CO₂ retention, were analyzed to evaluate CO₂ circulation efficiency. Simulation results reveal several critical findings. Elevated injection rates expanded the CO₂ plume, while bottomhole pressure at the producer controlled brine ingress from the regional aquifer. Once the CO₂ plume was fully developed, producer parameters emerged as dominant control factors. Completion designs at both wells proved vital in maximizing CO₂ recovery and suppressing liquid loading. Permeability variations showed limited influence, likely due to sand-dominated continuity and established plume connectivity at Aquistore. Visualizations of water saturation and CO₂ plume geometry underscore the need for constraint optimization to reduce fluid mixing and stabilize CO₂-rich zones. The study suggests that CO₂ trapped during circulation contributes meaningfully to permanent storage, offering dual environmental and energy benefits. The results emphasize the importance of not underestimating subsurface complexity when CO₂ circulation is expected to occur under realistic operating conditions. This understanding paves the way to guide future pilot tests, operational planning, and risk mitigation strategies in CCS-enabled geothermal systems. Full article

Climate change mitigation demands scalable, technologically mature solutions capable of addressing emissions from hard-to-abate sectors. Carbon Capture and Storage (CCS) offers one of the few ready pathways for deep decarbonization by capturing CO₂ at large point sources and securely storing it in deep geological formations. The long-term viability of CCS depends on well control strategies/injection schedules that maximize storage capacity, maintain containment integrity, ensure commercial deliverability and remain economically viable. However, current practice still relies heavily on manual, heuristic-based well scheduling, which struggles to optimize storage capacity while minimizing by-products such as CO₂ recycling within the high-dimensional space of interdependent technical, commercial, operational, economic and regulatory constraints. This study makes two contributions: (1) it systematically reviews, maps and characterizes these multidimensional constraints, framing them as an integrated decision space for CCS operations, and (2) it introduces an industry-ready optimization framework—Automated Optimization of Well control Strategies through Dynamic Time–Space Discretization—which couples reservoir simulation with constraint-embedded, hierarchical refinement in space and time. Using a modified genetic algorithm, injection schedules evolve from coarse to fine resolution, accelerating convergence while preserving robustness. Applied to a heterogeneous saline aquifer model, the method was tested under both engineering and financial objectives. Compared to an industry-standard manual schedule, optimal solutions increased net stored CO₂ by 14% and reduced recycling by 22%, raising retention efficiency to over 95%. Under financial objectives, the framework maintained these technical gains while increasing cumulative cash flow by 23%, achieved through leaner, smoother injection profiles that minimize costly by-products. The results confirm that the framework’s robustness, scalability and compatibility with commercial simulators make it a practical pathway to enhance CCS performance and accelerate deployment at scale. Full article

The development of large-scale, flexible, and safe hydrogen storage is critical for enabling a low-carbon energy system. Deep saline aquifers (DSAs) offer substantial theoretical capacity and broad geographic distribution, making them attractive options for underground hydrogen storage. However, hydrogen storage in DSAs presents complex technical, geochemical, microbial, geomechanical, and economic challenges that must be addressed to ensure efficiency, safety, and recoverability. This study synthesizes current knowledge on hydrogen behavior in DSAs, focusing on multiphase flow dynamics, capillary trapping, fingering phenomena, geochemical reactions, microbial consumption, cushion gas requirements, and operational constraints. Advanced numerical simulations and experimental observations highlight the role of reservoir heterogeneity, relative permeability hysteresis, buoyancy-driven migration, and redox-driven hydrogen loss in shaping storage performance. Economic analysis emphasizes the significant influence of cushion gas volumes and hydrogen recovery efficiency on the levelized cost of storage, while pilot studies reveal strategies for mitigating operational and geochemical risks. The findings underscore the importance of integrated, coupled-process modeling and comprehensive site characterization to optimize hydrogen storage design and operation. This work provides a roadmap for developing scalable, safe, and economically viable hydrogen storage in DSAs, bridging the gap between laboratory research, pilot demonstration, and commercial deployment. Full article

Offshore Carbon Capture, Utilization, and Storage (CCUS) is emerging as a critical strategy for achieving net-zero emissions, offering significant storage potential in depleted hydrocarbon reservoirs and deep saline aquifers while leveraging existing offshore infrastructure. This review summarizes recent advances in capture, transport, utilization, and storage technologies in the offshore industry. Case studies including Sleipner, Gorgon, and Northern Lights illustrate both the technical feasibility and the operational, economic, and regulatory challenges associated with large-scale deployment. While post-combustion capture and pipeline transport remain the most technologically mature approaches, significant uncertainties continue to exist regarding the logistics of marine transportation, reservoir integrity, and the robustness of monitoring frameworks. Policy and regulatory complexity, coupled with high capital costs and public acceptance issues, continue to constrain commercial viability. This review highlights that offshore CCUS holds significant promise but requires advances in monitoring technologies, cost reduction strategies, and harmonized international governance. Future research should focus on integrating CCUS with hydrogen production and renewable energy systems to accelerate large-scale deployment. Full article

Numerical simulations are essential for optimizing CO₂ geological storage in deep saline aquifers; however, their substantial computational demands pose a significant challenge. This study introduces an automated machine learning (ML)-driven grid block classification framework applied to a realistic deep saline aquifer model to accelerate numerical simulations while maintaining accuracy. The methodology employs an ML and interquartile range-based classifier to distinguish grid blocks as either fast- or slow-varying. ML-based proxy models are applied exclusively to slow-varying regions, while traditional iterative methods handle dynamic, fast-varying regions. Results confirm a considerable reduction in computational costs without compromising predictive accuracy. Validated under realistic reservoir conditions, the approach demonstrates scalability and robustness, supporting efficient, accurate large-scale CO₂ storage simulations and advancing sustainable subsurface sequestration strategies. Full article

The aim of this study is to compare the performance of the multi-layer and the single-layer CO₂ injection methods used in offshore carbon capture and storage (CCS) through TOUGH-FLAC numerical simulations. Four key indicators, namely CO₂ saturation, pore pressure, vertical displacement, and Coulomb Failure Stress (CFS), are employed as indices to assess the storage capacity of reservoirs and the mechanical stability of caprocks. Numerical simulation results show that the multi-layer injection method increases the CO₂ migration distance and reduces CFS values compared with the single-layer injection method. After 1 year of injection, the combined CO₂ migration distance across two aquifers in Case 3 is 610 m, which is greater than that obtained using single-layer injection in Cases 1 and 2 (350 m and 380 m, respectively). Additionally, deep saline aquifers demonstrate superior CO₂ storage capacity due to higher overburden pressure, which also reduces the risk of caprock failures. After 30 years of injection, in Cases 1 and 2, the maximum CFS values are 0.591 and 0.567, respectively, and the CO₂ migration distances are 2400 m and 2650 m, respectively. Overall, the findings of this study indicate that the multi-layer injection method, particularly in deep saline aquifers, provides a safer and more efficient CO₂ injection approach for offshore CCS projects. Full article

To reduce CO₂ emissions, CO₂ geological storage is recognized as an effective approach to decrease atmospheric carbon concentration. Sequestration in deep saline aquifers has become a research focus. However, the physicochemical property changes in saline formations induced by CO₂ injection remain unclear, making it difficult to assess their CO₂ storage potential. This study focuses on saline aquifers within the Jurassic Badaowan formation (J₁b), Sangonghe formation (J₁s), and Cretaceous Tugulu Group (K₁tg) of the Baijiahai Uplift in the Junggar Basin. An integrated methodology combining laboratory experiments—including CO₂ static immersion tests, dynamic displacement tests, X-ray diffraction (XRD), mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR) measurements, and mechanical testing—with CMG-based numerical modeling was employed to analyze CO₂ storage mechanisms and evaluate storage potential. The results show that after CO₂ immersion, extensive dissolution of calcite in J₁s, clay swelling/cementation in J₁b, and extensive dissolution of calcite in K₁tg all lead to increased porosity and permeability, with the J₁b formation exhibiting superior CO₂ storage capacity, the highest MICP-derived porosity, and the greatest NMR-measured porosity among the three formations. Numerical simulations further confirmed J₁b’s leading sequestration volume. Based on integrated experimental and simulation results, the J₁b formation is identified as the optimal reservoir for CO₂ storage. However, to manage potential mechanical instability during real-world injection scenarios, injection pressures and rates should be carefully controlled and continuously monitored to avoid formation fracturing and ensure long-term storage security. This study provides a reference for implementing saline aquifer CCUS projects. Full article

Salinization of deep groundwater is a significant environmental and economic challenge in arid and desert zones, driven by both natural processes and human activities. Understanding the causes and dynamics of groundwater salinity is essential for protecting water quality and ensuring sustainable resource use. This study presents a novel approach, using hybrid artificial intelligence methods built upon enhanced ensemble decision tree models (EdTE-ML), including CatBoost (CatBR-m), ExtraTrees (ExTR-m), and custom Bootstrapping Regressor (BsTR-m), within a two-stage predictive framework. This study focuses on a deep, stressed aquifer in the oasis zone of Kebili, in southwestern Tunisia’s desert region. In the first stage, CatBR-m and ExTR-m served as base models, generating predictive features for the BsTR-m model in the second stage. Despite relying on limited hydrochemical data from a small number of wells, both base models produced satisfactory results. The BsTR-m model in the second stage outperformed individual models in terms of accuracy, generalization to unseen data, and spatial identification of salinity-affected zones. The proposed methodology accurately predicts groundwater salinity levels, providing an effective tool for early detection of water quality degradation. This predictive capability supports more proactive and sustainable groundwater management strategies in vulnerable desert aquifer systems. Full article

Deep saline aquifers in the eastern part of Drava Basin were screened for potential storage sites. The input dataset included three seismic volumes, a rather extensive set of old seismic sections and 71 wells. Out of all identified potential storage objects, only two sites were found to be situated in the favorable geological settings, meaning that the inspected wells drilled through structural traps had a seal at least 20 m thick which was intersected by only a few faults with rather limited displacement. Many more closed structures in the area were tested by exploration wells, but in all other wells, various problems were encountered, including inadequate reservoir properties, inadequate seal or inadequate depth of the identified trap. Analysis was highly affected by the insufficient quality and spatial distribution of the seismic input data, as well as in places with insufficient quality of input well datasets. An initial characterization of identified storage sites was performed, and their attributes were compared, with potential storage object B recognized as the one that should be further developed. However, given the depth and increased geothermal gradient of the potential storage object B, it is possible that it will be developed as a geothermal reservoir, and this brings forward the problem of concurrent subsurface use. Full article

A vital step for any hydrochemical assessment is properly carrying out quality assurance and quality control (QA/QC) techniques to evaluate data confidence before performing the assessment. Understanding the processes governing groundwater evolution in coastal aquifers is critical for managing freshwater resources under increasing anthropogenic and climatic pressures. This study reassesses the hydrochemical and isotopic data from the Deep Confined Aquifer System (DCAS) in the Jiangsu Coastal Plain, China, by firstly applying QA/QC protocols. Anomalously high Fe and Mn concentrations in several samples were identified and excluded, yielding a refined dataset that enabled a more accurate interpretation of hydrogeochemical processes. Using hierarchical cluster analysis (HCA), principal component analysis (PCA), and stable and radioactive isotope data (δ²H, δ¹⁸O, ³H, and ¹⁴C), we identify three dominant drivers of groundwater evolution: water–rock interaction, evaporation, and seawater intrusion. In contrast to earlier interpretations, we present clear evidence of active seawater intrusion into the DCAS, supported by salinity patterns, isotopic signatures, and local hydrodynamics. Furthermore, inconsistencies between tritium- and radiocarbon-derived residence times—modern recharge indicated by ³H versus Pleistocene ages from ¹⁴C—highlight the unreliability of previous paleoclimatic reconstructions based on unvalidated datasets. These findings underscore the crucial role of robust QA/QC and integrated tracer analysis in groundwater studies. Full article

The distribution of fresh and salty groundwater is a critical factor affecting the coastal wetlands. However, the dynamics of groundwater flow and salinity in river deltas remain unclear due to complex hydrological settings and impacts of human activities. The uniqueness of the Yellow River Delta (YRD) lies in its relatively short formation time, the frequent salinization and freshening alternation associated with changes in the course of the Yellow River, and the extensive impacts of oil production and underground brine extraction. This study employed a detailed hydrogeological modeling approach to investigate groundwater flow and the impacts of oil field brine leakage in the YRD. To characterize the heterogeneity of the aquifer, a sediment texture model was constructed based on a geotechnical borehole database for the top 30 m of the YRD. A detailed variable-density groundwater model was then constructed to simulate the salinity distribution in the predevelopment period and disturbance by brine extraction in the past decades. Probabilistic particle tracking simulation was implemented to assess the alterations in groundwater flow resulting from brine resource development and evaluate the potential risk of salinity contamination from oil well fields. Simulations show that the limited extraction of brine groundwater has significantly altered the hydraulic gradient and groundwater flow pattern accounting for the less permeable sediments in the delta. The vertical gradient increased by brine pumping has mitigated the salinization process of the shallow groundwater which supports the coastal wetlands. The low groundwater velocity and long travel time suggest that the peak salinity concentration would be greatly reduced, reaching the deep aquifers accounting for dispersion and dilution. Further detailed investigation of the complex groundwater salinization process in the YRD is necessary, as well as its association with alternations in the hydraulic gradient by brine extraction and water injection/production in the oilfield. Full article

Geological storage of CO₂ in offshore deep saline aquifers is widely recognized as an effective strategy for large-scale carbon emission reduction. This study aims to assess the mechanical integrity and storage efficiency of reservoirs using a multi-layer CO₂ injection method in the Enping 15-1 Oilfield CO₂ storage project which is the China’s first offshore carbon capture, utilization, and storage (CCUS) demonstration. A coupled Hydro–Mechanical (H–M) model is constructed using the TOUGH-FLAC simulator to simulate a 10-year CO₂ injection scenario, incorporating six vertically distributed reservoir layers. A sensitivity analysis of 14 key geological and geomechanical parameters is performed to identify the dominant factors influencing injection safety and storage capacity. The results show that a total injection rate of 30 kg/s can be sustained over a 10-year period without exceeding mechanical failure thresholds. Reservoirs 3 and 4 exhibit the greatest lateral CO₂ migration distances over the 10-year injection period, indicating that they are the most suitable target layers for CO₂ storage. The sensitivity analysis further reveals that the permeability of the reservoirs and the friction angle of the reservoirs and caprocks are the most critical parameters governing injection performance and mechanical stability. Full article

Deep saline aquifers provide significant potential for CO₂ storage and are crucial in carbon capture, utilization, and storage (CCUS). However, ensuring the long-term safe storage of CO₂ remains challenging due to the complexity of coupled thermal, hydrological, mechanical, and chemical (THMC) processes. This study is one of a few to incorporate fault-controlled reservoir structures in the Enping 15-1 oilfield to simulate the performance of CO₂ geological storage. A systematic analysis of factors influencing CO₂ storage safety, such as the trap area, aquifer layer thickness, caprock thickness, reservoir permeability, and reservoir porosity, was conducted. We identified the parameters with the most significant impact on storage performance and provided suitable values to enhance storage safety. The results show that a large trap area and aquifer thickness are critical for site selection. Low permeability and large caprock thickness prevent CO₂ from escaping, which is important for long-term and stable storage. These findings contribute to developing site-specific guidelines for CO₂ storage in faulted reservoirs. Full article

With the consequences of climate change becoming more urgent, there has never been a more pressing need for technologies that can help to reduce the carbon dioxide (CO₂) emissions of the most polluting sectors, such as power generation, steel, cement, and the chemical industry. This review summarizes the state-of-the-art technologies for carbon capture, for instance, post-combustion, pre-combustion, oxy-fuel combustion, chemical looping, and direct air capture. Moreover, already established carbon capture technologies, such as absorption, adsorption, and membrane-based separation, and emerging technologies like calcium looping or cryogenic separation are presented. Beyond carbon capture technologies, this review also discusses how captured CO₂ can be securely stored (CCS) physically in deep saline aquifers or depleted gas and oil reservoirs, stored chemically via mineralization, or used in enhanced oil recovery. The concept of utilizing the captured CO₂ (CCU) for producing value-added products, including formic acid, methanol, urea, or methane, towards a circular carbon economy will also be shortly discussed. Real-life applications, e.g., already pilot-scale continuous methane (CH₄) production from flue gas CO₂, are shown. Actual deployment of the most crucial technologies for the future will be explored in real-life applications. This review aims to provide a compact view of the most crucial technologies that should be considered when choosing to capture, store, or convert CO₂, informing future researchers with efforts aimed at mitigating CO₂ emissions and tackling the climate crisis. Full article