Storage In Saline Aquifers Research Articles

An application of a genetic algorithm in co-optimization of geological CO2 storage based on artificial neural networks

Abstract Global warming, driven by human-induced disruptions to the natural carbon dioxide (CO2) cycle, is a pressing concern. To mitigate this, carbon capture and storage has emerged as a key strategy that enables the continued use of fossil fuels while transitioning to cleaner energy sources. Deep saline aquifers are of particular interest due to their substantial CO2 storage potential, often located near fossil fuel reservoirs. In this study, a deep saline aquifer model with a saline water production well was constructed to develop the optimization workflow. Due to the time-consuming nature of each realization of the numerical simulation, we introduce a surrogate aquifer model derived from extracted data. The novelty of our work lies in the pioneering of simultaneous optimization using machine learning within an integrated framework. Unlike previous studies, which typically focused on single-parameter optimization, our research addresses this gap by performing multi-objective optimization for CO2 storage and breakthrough time in deep saline aquifers using a data-driven model. Our methodology encompasses preprocessing and feature selection, identifying eight pivotal parameters. Evaluation metrics include root mean square error (RMSE), mean absolute percentage error (MAPE) and R2. In predicting CO2 storage values, RMSE, MAPE and R2 in test data were 2.07%, 1.52% and 0.99, respectively, while in blind data, they were 2.5%, 2.05% and 0.99. For the CO2 breakthrough time, RMSE, MAPE and R2 in the test data were 2.1%, 1.77% and 0.93, while in the blind data they were 2.8%, 2.23% and 0.92, respectively. In addressing the substantial computational demands and time-consuming nature of coupling a numerical simulator with an optimization algorithm, we have adopted a strategy in which the trained artificial neural network is seamlessly integrated with a multi-objective genetic algorithm. Within this framework, we conducted 5000 comprehensive experiments to rigorously validate the development of the Pareto front, highlighting the depth of our computational approach. The findings of the study promise insights into the interplay between CO2 breakthrough time and storage in aquifer-based carbon capture and storage processes within an integrated framework based on data-driven coupled multi-objective optimization.

Wettability alterations of amorphous shales in geological carbon storage: Impact of acidic conditions in deep saline aquifers

The feasibility of Geological carbon storage (GCS) in deep saline aquifers is mainly determined by its ability to prevent CO2 leakage through caprock, which is most commonly shale. The wettability of the shale–CO2–brine system is one of the most essential petro-physical parameters in the assessment of the integrity of shale caprock. Current literature suggests that wettability measurements of the shale–CO2–brine system have many contradictory outcomes. Furthermore, previous applications of molecular dynamic simulation (MDS) to estimate wettability of the shale–CO2–brine system disregarded variations in shale composition and concentrated on just a single component. Moreover, there has been limited investigation into the effect of CO2 dissolution in brine and the resultant acidic conditions on the wettability of the shale–CO2–brine combination. In this study, MDS is implemented for evaluating the wettability of a system made up of amorphous shale, CO2, and brine under conditions representative of typical geological storage site. An amorphous shale molecular model has been developed through the integration of illite, quartz, and kerogen. The microscopic wetting and half-angle fitting approaches have been applied to establish the wettability. A qualitative investigation was also conducted to further examine the wettability of the studied systems. Additionally, a contrasting analysis was conducted to assess the conclusions of this study in relation to relevant literature data. The findings of this study demonstrate the wettability of an amorphous shale–CO2–brine system is significantly influenced by the composition of the shale and the presence of acidic conditions. The water contact angles for shales with TOC values of 5% and 10% were measured to be 42.1° and 52.5°, respectively, at a pressure of 10 MPa and a temperature of 333 K, without taking into account any acidic conditions. The addition of induced acidic conditions resulted in a 15% and 24% increase in the water contact angle, respectively, for high and low TOC shale systems, respectively. The findings of this study have significant implications on the containment of stored CO2, thereby contributing to the worldwide efforts of minimizing greenhouse gas emissions through enhancements in the performance of GCS processes.

Numerical simulation study of CO2 storage capacity in Deep Saline aquifers

The storage of supercritical CO2 in deep saline aquifers is essential for reducing carbon emissions, and the selection of an appropriate reservoir is a primary consideration for carbon sequestration. To investigate the impact of reservoir physical properties on the CO2 storage capacity of saline aquifers, this study establishes a numerical simulation model of CO2 storage in deep saline aquifers and utilizes the MRST toolbox to solve it by the finite volume method. The research thoroughly analyzes the influence of reservoir physical properties on the CO2 migration process and CO2 storage capacity of the saline aquifer layer. The results show that prolonged CO2 injection involves a process of initially suppressing pressure and subsequently slowly diffusing it to the surroundings. Furthermore, the physical properties of the reservoir and the reservoir pressure significantly influence CO2 burial in deep saline aquifers. Higher reservoir permeability and deeper burial depth result in enhanced CO2 storage and faster CO2 plume migration. However, the porosity and temperature of the reservoir have a negligible impact on CO2 storage. Our research work provides a precise understanding of selecting suitable layers for CO2 storage in deep saline aquifers, offering strong support for early predictions of carbon capture, utilization, and storage (CCUS).

Modelling the solubility of gases in aqueous solutions with a focus on geothermal applications– assessment and benchmarking of two free software packages

The interactions between aqueous solutions, gases, and minerals dictate the extent of issues such as scaling, degassing, and corrosion, which have a major impact on the performance of a vast number of industrial applications (e.g., geothermal plants, oil and gas production facilities, natural gas storage in saline aquifers, flue gas scrubbing, carbon sequestration, etc.). Among the different software programs available for aqueous chemistry calculations, Phreeqc and Reaktoro were tested and validated against a wide dataset of gas solubility measurements. For the datasets considered, the two programs essentially led to the same outcome with only a few discrepancies observed. Yet, the agreement between the models and experimental data was greatly affected by the selected database. The models implemented in Phreeqc and Reaktoro were also compared with the experimental bubble point pressure of fluids sampled at several geothermal wells. The satisfactory performance of both Phreeqc and Reaktoro for describing different chemical systems at a wide range of pressures and temperatures showcases their versatility and practicality for assisting in the design and optimization of various processes relevant to the energy transition (e.g., geothermal exploitation, CO2/H2 transport and storage).

CO2-enhanced oil recovery with CO2 utilization and storage: Progress and practical applications in China

CO2 capture, utilization, and storage (CCUS) is a strategic emerging technology that has undergone rapid development in recent years. CO2-Enhanced oil recovery with CO2 utilization and storage (CCUS-EOR) is currently the most practicable large-scale carbon reduction technology and has become a key tool for large-scale applications of CCUS. In the inceptive period, CCUS-EOR was targeted towards flooding, but has since been extensively adopted for industrialization. At present, CCUS-EOR is being developed for synergistic flooding and storage, and is expected to gradually transition to utilization in geological storage for supporting large-scale carbon reduction to achieve the goal of carbon neutrality. The primary mechanisms controlling CCUS-EOR differ for high-permeability, high-water-cut oil reservoirs; low-permeability oil reservoirs; extra-low permeability oil reservoirs; and tight and shale oil reservoirs. Therefore, identifying the main constraints in the CO2 flooding process and formulating effective development strategies are necessary for maximizing both oil recovery and storage. In the geological storage of CO2, attention must be paid to key factors such as the storage capacity, injectivity, and safety. The storage performance can be enhanced through methods such as synergistic CO2-enhanced water recovery and CO2 storage (CCS-EWR), as well as rapid carbon mineralization in basalt. Globally, CCUS projects have undergone rapid growth, with more than 90 % of operational projects led by or involving oil and gas companies. In China, CCUS-EOR is currently in the early stage of industrial application. The first million-ton CCUS project has recently been completed. China has great potential for CCUS-EOR. An advantage of CCUS-EOR is the early adoption to large-scale applications, while CO2 storage in saline aquifers provides a foundation for promoting large-scale development. In the future, multiple CCUS-EOR clusters are expected to be established in the Bohai Bay Basin, Songliao Basin, Ordos Basin, Yangtze River Delta, and Pearl River Delta regions, which will drive high-quality development of CCUS applications in China. ChineseLibrary Classification Number TE341. Document CodeA.

Experimental and modeling study of CO2 solubility in formation brines at in-situ conditions

The dissolution of CO2 into formation brine, one of the dominant trapping mechanisms for geological carbon storage (GCS) in deep saline aquifers, has been widely investigated. Most experimental and modeling studies focused on the CO2 solubility in synthetic brines. However, rare studies have been performed to investigate CO2 solubility in real formation brines, especially when ion-ion interactions were considered. In this work, the CO2 solubility of seventy formation brines from major basins in China including the Junggar basin, Ordos basin, and North and South Songliao basin was measured at in-situ pressure and temperature conditions. Experimental results show that CO2 solubility has a strong relationship with pressure and total dissolved solids (TDS), while the relationship between solubility and temperature is weak. Three solubility regions were classified in terms of depth. In Regions I and III, CO2 solubility increases with depth and is independent with depth in Region II. However, the effect of salinity on CO2 solubility was observed in all regions. Additionally, a modified Duan's model used for a mixed-salt system was proposed using dataset from this study and literature. Comparisons with Duan's model for CO2 solubility in mixed-salt systems show the average absolute relative deviation equals 5.14%, which reveals a clear improvement in the modified model. In addition, the validation of the model was performed, and results show that the average absolute relative deviation before and after improvement are 12.10% and 5.11%, respectively, indicating the high accuracy of the improved model. Overall, this research improves the understanding of CO2 solubility in real formation brines and illustrates the efficiency and accuracy of the modified model, which is crucial for the evaluation of the CO2 storage capacity, fate of CO2 over storage site life for commercial GCS projects.

CO2 soluble surfactants for carbon storage in carbonate saline aquifers with achievable injectivity: Implications from the continuous CO2 injection study

Continuous CO2 injection (CCI) into saline aquifers suffers from low sweep efficiency. While utilizing foam can effectively address this issue, a relatively potent foam design may undesirably reduce the injectivity of CO2. In this study, the potential of CO2-soluble surfactants assisted carbon storage in carbonate saline aquifers was evaluated by core flooding tests and numerical simulations. It is found that foam can be generated at the displacement front during continuous CO2 injection with 0.39 g/L surfactant (CCI + S, fg = 100 %). The CO2 saturation can reach 60 % after 1.0 pore volume of CCI + S, approximately 50 % higher than that of CCI. The maximum pressure gradient is around 1.5 psi/ft at an injection rate of 1.0 ft/d in 162 mD Indiana Limestone for CCI + S. The effects of surfactant concentration, foam quality, and rock permeability were also investigated by core flooding. Moreover, the influence of surfactant partitioning and adsorption on CO2 transport behavior was systematically evaluated by numerical simulation in synthetic and geological models, using modeling parameters that are realistic for field applications. The advantage of injecting surfactant with CO2 is more evident in heterogeneous saline aquifers. Such novel injection strategy provides a promising approach for carbon sequestration in saline aquifers by controlling the mobility of CO2 at the displacement front and simultaneously maintaining acceptable injectivity in the field. The CCI + S process may also impose less risk to the caprock. Expanding the potential CO2 storage sites to heterogeneous saline aquifers could be a game-changer. Our understanding of foam dynamics in porous media could also be advanced.

Investment Evaluation of CCUS Retrofitting for Coal-to-Liquid Industry in China

Coal-to-oil (CTL) combined with carbon capture, utilization and storage (CCUS) can significantly reduce the CO2 emissions generated in the production process to achieve clean coal utilization. Taking CTL enterprises as sources and deep saline aquifers and oil fields as sinks, this paper establishes a source–sink matching model, which is combined with a trinomial tree real-option model of carbon price fluctuation, and evaluates the investment decisions of CTL. The results show that 36 pipelines with an average transportation distance of 319.13 km and predominantly small diameters must be constructed for CO2 capture and storage combined with enhanced oil recovery (EOR). Under the current carbon price, 83.33% of enterprises can invest immediately when adopting EOR; when utilizing storage in a deep saline aquifer (DSF), even with a 50% subsidy and a decrease in costs due to the learning rate, enterprises still need to execute the deferred option investment. Government subsidies and technological advances can greatly increase the value of investment. The critical carbon price of CTL-CCUS projects is sensitive to government subsidies, technological advances, and CO2 transportation distances. Therefore, China should reasonably guide the development of the carbon market and give play to the role of the carbon market in emission reduction incentives. In addition, the Chinese government can provide direct financial support for the CTL-CCUS project to increase the enthusiasm of CTL enterprises for CCUS transformation and promote technological progress.

Minireview on CO2 Storage in Deep Saline Aquifers: Methods, Opportunities, Challenges, and Perspectives

Minireview on CO₂ Storage in Deep Saline Aquifers: Methods, Opportunities, Challenges, and Perspectives

Induced Seismicity Hazard Assessment for a Potential CO2 Storage Site in the Southern San Joaquin Basin, CA

California’s Central Valley offers vast opportunities for CO2 storage in deep saline aquifers. We conducted an induced seismicity hazard assessment for a potential injection site in the southern San Joaquin Basin for 18 years of injection at 0.68 MtCO2/yr and 100 years of monitoring. We mapped stress, faults, and seismicity in a 30 km radius around the site to build a geomechanical model and resolve the stresses on major faults. From a 3D hydromechanical simulation of the CO2 plume, we calculated the change in pressure over time on these faults and determined the conditions for safe injection. Lacking any subsurface imaging, we also conducted a probabilistic fault slip analysis using numerous random distributions of faults and a range of geomechanical parameters. Our results show that the change in probability of fault slip can be minimized by controlling the size, migration, and magnitude of the pressure plume. We also constructed a seismic catalog for the last 20 years around the site and characterized the natural patterns of seismicity. We use these results to establish criteria for evaluating potential-induced events during the storage period and to develop a traffic light response system. This study represents a first-order procedure to evaluate the seismic hazards presented by CO2 storage and incorporate uncertainties in hydrological and geomechanical parameters.

Thermodynamic Properties of a Gas–Liquid–Solid System during the CO2 Geological Storage and Utilization Process: A Review

Emission reduction in the main greenhouse gas, CO2, can be achieved efficiently via CO2 geological storage and utilization (CCUS) methods such as the CO2 enhanced oil/water/gas recovery technique, which is considered to be an important strategic technology for the low-carbon development of China’s coal-based energy system. During the CCUS, the thermodynamic properties of the CO2–water–rock system, such as the interfacial tension (IFT) and wettability of the caprock, determine the injectability, sealing capacity, and safety of this scheme. Thus, researchers have been conducting laboratory experiments and modeling work on the interfacial tension between CO2 and the water/brine, wettability of caprocks, the solubility of gas–liquid binary systems, and the pH of CO2-saturated brine under reservoir temperature and pressure conditions. In this study, the literature related to the thermodynamic properties of the CO2–water–rock system is reviewed, and the main findings of previous studies are listed and discussed thoroughly. It is concluded that limited research is available on the pH of gas-saturated aqueous solutions under CO2 saline aquifer storage conditions, and less emphasis has been given to the wettability of the CO2–water/brine–rock system. Thus, further laboratory and modeling research on the wettability alternations of caprock in terms of molecular dynamics is required to simulate this phenomenon at the molecular level. Moreover, simplified IFT and solubility prediction models with thermodynamic significance and high integrity need to be developed. Furthermore, interaction mechanisms coupling with multi-factors associated with the gas–liquid–solid interface properties and the dissolution and acidification process need to be explored in future work.

Numerical sensitivity analysis of CO2 mineralization trapping mechanisms in a deep saline aquifer

There is a growing interest in geo-sequestration of CO2 for its safe disposal given the emergency of global greenhouse gas emissions reduction. Depleted oil and gas fields and deep saline aquifers are the most promising CO2 storage locations. Deep saline aquifers have been regarded preferable due to their widespread and great storage capacity. However, there exists a notable research gap regarding the understanding of CO2 geochemical reactivity with in-situ minerals, specifically in deep saline aquifers. Hence, this study focuses on the mineralization trapping mechanisms of CO2 by simulating the sequestration of at least 48 million tons of CO2 over a five-year period in a saline aquifer. The effectiveness of CO2 mineralization trapping for the siliciclastic aquifer was analyzed and characterized in relation to injection period, pressure, temperature, and salinity. The ability of the aquifer to store significant amounts of injected CO2 for a duration of 1000 years was studied using a numerical simulator. Our study also examines geochemical-induced changes, such as pH and porosity, resulting from mineralization. The results reveal that longer injection periods enhance the efficiency of CO2 mineralization trapping, primarily due to the increased availability of CO2 in the reservoir. Moreover, our findings provide valuable insights into the optimal mineralization temperatures for the simulated minerals, determining their dissolution or precipitation tendencies. Notably, calcite and dolomite exhibit higher mineralization efficiency at medium and lower temperatures, while minerals like illite, kaolinite, K-feldspar, and quartz are more favorably reactive at higher temperatures. Although porosity and pH exhibited minimal variations, they were sufficient to indicate the dynamics of mineral reactivity and mineralization trapping efficiency. By addressing these research gaps and presenting our novel findings, this study significantly contributes to the understanding of CO2 storage in deep saline aquifers and offers valuable insights for optimizing CO2 mineralization processes.

Trend of global carbon dioxide capture, utilization and storage industry and challenges and countermeasures in China

This paper systematically reviews the trend of carbon dioxide capture, utilization and storage (CCUS) industry in the world and China, presents the CCUS projects, clusters, technologies and strategies/policies, and analyzes the CCUS challenges and countermeasures in China based on the comparison of CCUS industrial development at home and abroad. The global CCUS development has experienced three stages: exploration stage, policy driven stage, and dual-drive stage. Currently, the active large-scale CCUS projects around the world focus on enhanced oil recovery (EOR) and are expanding into storage in saline aquifers. The CCUS industry of China has evolved in three stages: exploration, pilot test, and industrialization. In the current critical period of transition from field test to industrialization, China's CCUS projects are EOR-dominated. By comparing the industrial development of CCUS in China and abroad, it is found that the scale-up and industrialization of CCUS in China face challenges in technology, facilities and policies. Finally, future solutions to CCUS development in China are proposed as follows: strengthening the top-level design and planning of CCUS; developing high-efficiency and low-cost CCUS technologies throughout the whole industrial chain; deploying CCUS oil and gas + new energy clusters; improving the policy support system of CCUS; and strengthening discipline construction and personnel training, etc.

Numerical Comparison of Hydrogen and CO2 Storage in Deep Saline Aquifers from Pore Scale to Field Scale

Numerical Comparison of Hydrogen and CO2 Storage in Deep Saline Aquifers from Pore Scale to Field Scale

Pore‐Scale Modeling of Coupled CO2 Flow and Dissolution in 3D Porous Media for Geological Carbon Storage

AbstractDissolution trapping is one of the crucial trapping mechanisms for geological carbon storage in deep saline aquifers. The injected supercritical CO2 (scCO2) flow and dissolution processes are coupled and interact with each other. Therefore, we performed direct numerical simulations in three‐dimensional micro‐CT images of sandstones using the volume of fluid and continuous species transfer method. We investigated the coupled scCO2 flow and dissolution processes at pore‐scale under different rock structures, capillary numbers, and rock wettability conditions. The dynamic evolution of the scCO2/brine phase distribution and scCO2 concentration distribution occurring during the injection period were presented and analyzed. Complicated coupling mechanisms between scCO2‐brine two‐phase flow and interphase mass transfer were also revealed. Our results showed that the scCO2 dissolution was highly dependent on the local distribution of scCO2 clusters. The rock with relatively high porosity and permeability would have more capacity for scCO2 injection resulting in a faster and greater dissolution of scCO2 in brine. The effect of capillary number on the scCO2 dissolution process was related to the range of capillary number. The effective upscaled (macro‐scale) mass transfer coefficient (kA) during scCO2 dissolution was evaluated, and the power‐law relationship between kA and Péclet number was obtained. Rock wettability was found to be another factor controlling the scCO2 dissolution process by affecting the scCO2‐brine interfacial area. Our pore‐scale study provides a deep understanding of the scCO2 dissolution trapping mechanism, which is important to enhance the prediction of sequestration risk and improve sequestration efficiency.

Migration characteristics and local capillary trapping mechanism after the CO2 leakage out of saline aquifers

CO2 may leak from the wellbore, cross-section of faults, fractures, and pore space due to geological tectonic activity or human-induced activity during the CO2 geological storage in deep saline aquifers. To evaluate the CO2 leakage risk and select safe saline aquifers, it is necessary and crucial to predict the CO2 migration characteristics and trapping mechanism after its leakage. Although some previous studies have shown that heterogeneous capillary pressure can change CO2 migration path, its impact on the migration and storage after CO2 leakage is still unclear. Therefore, a simulation model of CO2 leakage and migration in saline aquifers is established by adopting stochastic modeling in geology and two-phase seepage modeling in the fluid. Based on the model, the influence of capillary pressure heterogeneity and caprock factors (thickness and leakage area) on the leaked CO2 migration, distribution, and trapping is analyzed quantitatively. The research result shows that heterogeneous capillary pressure in the saline aquifers can effectively trap the leaked CO2 and enlarge the lateral swept volume of leaked CO2. With the increase of capillary pressure and its heterogeneity, the upward migration of CO2 slows down but the local capillary trapping increases. Both of these can weaken the risk of CO2 leakage to the surface. Under the local capillary trapping above and below the caprock, the increasing of caprock thickness and leakage area have little effect on CO2 leakage amount, but may increase the local capillary trapping and make the formation safer. Therefore, priority should be given to selecting saline aquifers with thicker caprock to reduce the potential risk of CO2 leakage. In order to ensure the safety of CO2 storage, a saline aquifer with strong capillary pressure heterogeneity and good trapping performance should be selected.

Simulation Study of sc-CO2 Based Silylation for Decreasing Severity of Water Blockage and Salt Precipitation during Geological CO2 Storage in Deep Saline Aquifers

Deep saline aquifers are often favorable for underground CO2 sequestration due to their large capacity and relatively low likelihood for resource conflicts. However, many possible issues can arise during CO2 injection. Often these aquifers have a significant salinity level (as these often present minimal resource conflict issues) and as such salt precipitation near the injection wellbore can be problematic. Furthermore, when water blockage occurs, salt precipitation can be exacerbated since large amounts of water remain near the wellbore. Altering the rock wettability towards less water-wet can alleviate water blockage and in turn reduce the likelihood or severity of salt precipitation. Previous lab experiments have shown that supercritical CO2 (sc-CO2)-based silylation can effectively functionalize rock surfaces with hydrophobic silanes. In this study, numerical models were constructed to evaluate the combined effects of multi-phase fluid flow, water evaporation and salt precipitation assuming a change in wettability (thus impacting the relative permeability characteristics of the reservoir) resulting from the silylation process. The aim of this study is to evaluate the efficacy of this chemical treatment to address near wellbore salt precipitation induced by CO2 injection. According to the simulation results, a decrease in injectivity due to salt precipitation is more significant when water blockage is also present. Injectivity is deteriorated prominently in high salinity reservoirs with water blockage since evaporation into the injected CO2 phase will cause significant salt precipitation. In a representative formation, the injectivity decline is worse (up to 68.6% relative injectivity change (RIC)) when both salt precipitation and water blockage are considered since the latter provides more trapped brine inducing more salt accumulation around the wellbore. With hydrophobic silylation, the combined effects of salt precipitation and water blockage on RIC are decreased on an absolute basis by up to 7%. Depending on techno-economic considerations, this method is encouraged to be implemented as early as possible during a CO2 injection program to minimize salt accumulation from the outset.

Numerical study of the efficiency of underground hydrogen storage in deep saline aquifers, rock springs uplift, Wyoming

Underground hydrogen storage (UHS) is able to store a large amount of energy with efficiency, thus meeting the high demand for energy in winter. This study aims at investigating the feasibility and efficiency of UHS in the Nugget Sandstone, Rock Springs Uplift, Wyoming. The representative geological model is first constructed with the control of well logs and seismic data. Then the multiphase flow functions are well coupled into the subsurface reservoir model. Following that, based on the uncertainty of reservoir parameters, gas source accessibility, and production cost, the effects of key parameters on H2 fate within the reservoir and H2 recovery efficiency are researched. Simulation outcomes reveal that H2 dissolution into formation brine gives rise to a lower amount of trapped H2 within the reservoir but the recovery ratio is reduced by the H2 dissolution at the end. Relative permeability hysteresis can not only relieve the H2 vertical migration, but also give a wider H2 radial distribution. As the cycle proceeds, relative permeability hysteresis results in the notable enhancement in the trapped H2, leading to a reduction of the final recovery ratio from 0.86 to 0.76 when the residual gas saturation, Sgmax, ranges from 0.2 to 0.4. A slower cushion gas (CG) injection rate gives rise to a smaller final trapped H2, which accordingly results in an increase of recovery ratio. Further, the final recovery ratio changes from 0.835 to 0.846 due to an increase in working gas components from H2:CH4 = 1:1 to H2:CH4 = 3:1. The insights obtained in this study shed a light on accelerating the achievements of decarbonisation goals through the commercial-scale energy conversion and transition from conventional fossil energy and renewable energy to hydrogen.

Progress for carbon dioxide geological storage in West Macedonia: A field and laboratory-based survey.

Background: It is widely acknowledged that carbon dioxide (CO 2), a greenhouse gas, is largely responsible for climatic changes that can lead to warming or cooling in various places. This disturbs natural processes, creating instability and fragility of natural and social ecosystems. To combat climate change, without compromising technology advancements and maintaining production costs at acceptable levels, carbon capture and storage (CCS) technologies can be deployed to advance a non-disruptive energy transition. Capturing CO 2 from industrial processes such as thermoelectric power stations, refineries, and cement factories and storing it in geological mediums is becoming a mature technology. Part of the Mesohellenic Basin, situated in Greek territory, is proposed as a potential area for CO 2 storage in saline aquifers. This follows work previously done in the StrategyCCUS project, funded by the EU. The work is progressing under the Pilot Strategy, funded by the EU. Methods: The current investigation includes geomechanical and petrophysical methods to characterise sedimentary formations for their potential to hold CO 2 underground. Results: Samples were found to have both low porosity and permeability while the corresponding uniaxial strength for the Tsotyli formation was 22 MPa, for Eptechori 35 MPa and Pentalofo 74 MPa. Conclusions:The samples investigated indicate the potential to act as cap-rocks due to low porosity and permeability, but fluid pressure within the rock should remain within specified limits; otherwise, the rock may easily fracture and result in CO 2 leakage or/and deform to allow the flow of CO 2. Further investigation is needed to identify reservoir rocks as well more sampling to allow for statistically significant results.

Monte Carlo simulation of the maximum migration distance of CO[formula omitted] in a sloping aquifer

Carbon capture and storage in saline aquifers is broadly considered a viable technology for reducing anthropogenic impact on the environment. However, a secure CO2 storage can be compromised by the depositional environments of target reservoirs, which can influence the CO2 migration in subsurface. The disposal of CO2 in a sloping aquifer can result in a substantial gas migration in the updip direction from the injection well until all gas becomes trapped. It thus can reach far more than desired regions from the well where the potential leakage paths to the surface can exist. This study aims at understanding the principal parameters that the maximum migration distance in the updip direction depends on, which can be important for estimating the risks of CO2 leakage through old abandoned wells in the regions of intensive subsurface exploration. Using the Monte Carlo method, an extended parametric study is performed by running 3-D reservoir simulations of CO2 storage in random aquifers characterized by various petrophysical and thermobaric parameters, saturation functions and brine salinity, and for the wells operated under different target rates. Herewith, the modeling accounts for such relevant physical phenomena as the phase transitions, the gravity and capillary forces, the hysteresis behavior of the relative permeability, etc. It is shown that the maximum migration distance at the post-injection stage is characterized by just two similarity criteria and the critical gas saturation for the drainage and imbibition processes. It is found that the CO2 plume shape at the moment of the well shut-in influences the subsequent gas transport. A new simple relation parameterizing the revealed dependence is proposed and validated against the sampled maximum migration distances. The relation is useful for an instant estimating the size of the contaminated zone around a projected CO2 well and for ranking the potential storage sites.