Potential CO2 Leakage Research Articles

Physicochemical behavior and impact of CO2 and CH4 plumes during gas-rich water leakage in a shallow carbonate freshwater aquifer

Carbon capture and storage (CCS) is a promising technology for reducing CO2 emissions. Significant concerns have emerged about the potential leakage of CO2 into shallow aquifers, highlighting the risk to water quality and environmental safety. This underscores the importance of finding monitoring tools suitable for different geological scenarios. If leakage occurs in the context of depleted reservoirs being used for CO2 storage, residual CH4 from the storage complex will likely be entrained together with CO2. However, few studies have addressed the implications of CH4 presence and its potential as a monitoring parameter during CO2 leakage.To address this gap, we simulated a leakage event by injecting water enriched with CO2 and CH4 into a shallow limestone aquifer. The impact of the injection was monitored using a combination of laboratory measurements on water samples and in-situ sensors located downstream from the injection well.All parameters were affected by the simulated leakage. Some monitoring tools allowed us to differentiate the leakage event from natural variations. A key finding of this study was that at 7 m from the injection well, the CH4 breakthrough occurred roughly one day before the CO2 breakthrough, highlighting the potential of CH4 as an early indicator of CO2 leakage and suggesting interesting prospectives for industrial-scale sites. However, further research is needed to confirm the potential of CH4 as a CO2 leakage indicator at industrial scales, due to potential methane oxidation and loss of the signal with longer times and distances.This study contributes to a better understanding of the potential risks and effective monitoring strategies associated with CO2-CH4 leakage in carbonate aquifers.

Heuristic algorithms for design of integrated monitoring of geologic carbon storage sites

Designs for Risk Evaluation and Management (DREAM) is a tool developed under the National Risk Assessment Partnership (NRAP) to enhance geologic carbon storage safety and efficiency. Using potential leakage scenarios generated externally by the users preferred history-matching approach, DREAM constructs ideal combinations of sensor locations in the right place at the right time to detect as many leaks as possible, detect them as early as possible, and minimize cost. This user-friendly tool, developed in Java, features a window-based GUI for input and a 3D visualization tool for viewing the domain space and optimized monitoring plans. DREAM's latest version accommodates real-world usage by allowing for joint optimization of wellbore point sensor placements and surface geophysics survey geometries, and by using more efficient multi-objective optimization algorithms. In an example shown here, these two improvements combined allow us to support containment assurance and go from detecting 80–90 % of the potential CO2 leakage to +99.7 %, a step-change improvement that can make the deciding difference in whether a site is suitable for geologic carbon storage. Though developed for geologic carbon storage, this tool would be equally applicable in many surface or offshore environmental monitoring projects.

Experimental study for visualizing CO2-dissolved water plume migration under hydraulic gradient conditions and implication for field monitoring data

Investigating the possible direction of a CO2-dissolved water plume migration near the potential CO2 leakage area is a significant task because it helps estimate the spatial and temporal monitoring scale to detect the signal of released CO2 from the storage. Accordingly, the Korea CO2 Storage Environmental Management (K-COSEM) research center tried to develop an intensive monitoring system and applied it to the artificial CO2 release test in the actual field. Monitoring data from the field tests depicted the horizontal movement of the CO2-dissolved water plume along the direction of the groundwater flow. However, it remains unclear how the CO2-dissolved water plume migrates vertically and how gas accumulation occurs near the capillary zone. The present study simulated the CO2 release test with a visual expression method utilizing a Hele-Shaw cell with hydraulic gradient conditions (i = 0, 0.1, and 0.01) and tried to estimate the significant influences on a diffusive-advective transport of the dissolved gas plume with the shallow aquifer condition. The visualization experiment results were intuitively verified to determine whether the theoretical principles of action related to plume flow applied in this context. The results suggest that a CO2-dissolved water plume is distributed by hydraulic gradients and density-driven CO2 convective flow. The plume shape, center, and area were analyzed using an image analyzer program; the results demonstrated that the plume characteristic evolved depending on the significant effects on the plume. When the plume was mainly affected by the hydraulic gradient, it rapidly moved from the injection point to the last boundary; in contrast, when it was influenced primarily by density-driven CO2 convective flow, it flowed diagonally downward in the shape of varied branches. The numerical model calculated the migration of the CO2-dissolved water plume affected by both factors. The laboratory experiment and numerical simulation results suggest that the migration of a CO2-dissolved water plume may be affected by the hydraulic gradient and density-driven CO2 convective transport. As such, these factors should be considered when designing and analyzing CO2 monitoring signals to detect CO2 leaks from shallow aquifer systems.

Deep learning-assisted Bayesian framework for real-time CO2 leakage locating at geologic sequestration sites

Accurate and efficient localization of CO2 leakage if occurred in subsurface formations, is of significant importance in achieving secure geological carbon sequestration (GCS) projects. However, this task is inherently challenging due to the considerable uncertainties in the subsurface. In this work, we develop a novel deep learning-assisted Bayesian framework for identifying potential CO2 leakage sites based on the reservoir pressure transient behavior measured at the wellbores of injection or observation wells. The method consists of two essential steps: 1) Deep learning surrogate: This step aims to effectively replace the intensive high-fidelity simulation with an efficient deep learning surrogate. 2) Bayesian inversion: In this step, the posterior distributions of potential CO2 leakage locations are inverted, in which the surrogate serves as the forward model. The above two processes are automated using Bayesian optimization instead of a labor-intensive trial-and-error approach. The proposed framework is verified using a 3D geological model simulating CO2 sequestration into a brine-filled reservoir. The results demonstrate the Bayesian-optimized surrogate could successfully capture the underlying process of subsurface CO2-brine flow. The Bayesian inversion algorithm enables localizing CO2 leakage with high accuracy. To our knowledge, the proposed Bayesian framework is implemented for the first time to locate multiple leakage sites at the field scale. The proposed workflow provides an accurate and efficient approach to detecting possible CO2 leakage locations in a real-time manner and has promising potential for field-scale GCS applications.

Numerical modelling of CO2 leakage through fractured caprock using an extended numerical manifold method

In this study, the cohesive element-based numerical manifold method (Co-NMM) and unified pipe network method (UPM) are further developed and integrated to analyze the CO2 leakage through fractured caprock considering CO2-water two-phase flow, CO2 adsorption and deformation of both caprock matrix and fractures. First, the Co-NMM is modified to better treat complex discrete fracture networks (DFNs) problems, while the CO2 adsorption effect is introduced into the UPM governing equation of two-phase seepage. And then, a two-phase seepage-stress coupling model and an implicit sequential solution are successively adopted to combine the Co-NMM and UPM tightly to capture the interplay between the two-phase flow and fractured caprock accurately and flexibly. The extended Co-NMM formulation is verified by reproducing the CO2 plume distribution evolution process in deep brine aquifers for geological sequestration. Finally, we conduct a series of simulations where CO2 displaces water through caprock formation with different DFNs that serve as a dominant conduit for potential CO2 leakage from storage reservoirs. The effects of DFN connectivity and hydraulic characteristics on the CO2 leakage through caprock are discussed. The research results can offer a reference for the evaluation of caprock sealing efficiency and also indicate that the modified hybrid NMM-UPM method is a potentially effective tool for analyzing CO2 leakage through fractured caprock under complex DFN conditions.

Performance analysis of various machine learning algorithms for CO2 leak prediction and characterization in geo-sequestration injection wells

The effective detection and prevention of CO2 leakage in active injection wells are paramount for safe carbon capture and storage (CCS) initiatives. This study assesses five fundamental machine learning algorithms, namely, Support Vector Regression (SVR), K-Nearest Neighbor Regression (KNNR), Decision Tree Regression (DTR), Random Forest Regression (RFR), and Artificial Neural Network (ANN), for use in developing a robust data-driven model to predict potential CO2 leakage incidents in injection wells. Leveraging wellhead and bottom-hole pressure and temperature data, the models aim to simultaneously predict the location and size of leaks. A representative dataset simulating various leak scenarios in a saline aquifer reservoir was utilized. The findings reveal crucial insights into the relationships between the variables considered and leakage characteristics. With its positive linear correlation with depth of leak, wellhead pressure could be a pivotal indicator of leak location, while the negative linear relationship with well bottom-hole pressure demonstrated the strongest association with leak size. Among the predictive models examined, the highest prediction accuracy was achieved by the KNNR model for both leak localization and sizing. This model displayed exceptional sensitivity to leak size, and was able to identify leak magnitudes representing as little as 0.0158% of the total main flow with relatively high levels of accuracy. Nonetheless, the study underscored that accurate leak sizing posed a greater challenge for the models compared to leak localization. Overall, the findings obtained can provide valuable insights into the development of efficient data-driven well-bore leak detection systems.

Analysis of carbon dioxide disposal methods to reduce greenhouse gases

The practice of capturing, storing and utilizing CO2 is becoming key to developing sustainable energy and industrial solutions. The technology promotes the use of fossil fuels, which remain the predominant source of energy worldwide. The effectiveness of the technology is evident in the reduction of CO2 levels in the atmosphere, a significant contribution to the reduction of global greenhouse gas (GHG) emissions and the fight against climate change. However, a notable concern in the realm of geological storage revolves around the potential leakage of CO2 from storage reservoirs. Carbon dioxide has the capability to migrate from the storage site, reaching both the surface and underground formations. Surface leakage presents health risks to humans, animals, and plants. The solution to this problem requires a detailed approach and should be solved through an inverse problem, in which pressure measurements in monitoring wells will be performed frequently to obtain information about the reservoir and possible leaks. Additionally, there are a number of issues with carbon dioxide leakage during oil and gas extraction, as well as various operations at fields. Emphasizing the monitoring of CO2 leakage, this paper underscores the importance of developing an algorithm designed to proactively prevent CO2 leakage in aquifers and depleted reservoirs. Such an initiative is pivotal in the broader context of mitigating greenhouse gas emissions. The paper offers an overview of methodologies for effective monitoring, management and modeling of CO2 leakage and practical approaches to calculation and assessment, contributing to a more complete understanding of the challenges associated with CO2 storage.

Optimizing a monitoring scheme for CO2 geological sequestration: An environmentally sustainable and cost-efficient approach

CO2 geological storage in depleted oil and gas reservoirs is recognized as a vital approach to combat anthropogenic CO2 emissions. However, the associated challenges of high operational costs and potential CO2 leakage necessitate the development of a cost-effective and environmentally sustainable monitoring program. This study presents a multi-objective optimization model aimed at designing an efficient CO2 monitoring program that meets both economic and environmental requirements. The model is applied to a case study of a Carbon Capture and Storage project in Shaanxi, utilizing an enhanced strengthen elitist genetic algorithm to solve the model under various scenarios. The analysis results demonstrate that in any scenario, a 10 % increase in the required monitoring technology precision leads to an average 1 % rise in monitoring costs, highlighting the cost-effectiveness of the CO2 monitoring scheme developed using our model. Furthermore, when environmental targets are raised by 10 times, monitoring costs show an average increase of 0.92 times, further illustrating the environmentally sustainable nature of our proposed CO2 monitoring scheme. In conclusion, this study provides a cost-effective and environmentally sustainable method framework for the development of CO2 geologic sequestration monitoring scheme, which can contribute to the practical implementation of Carbon Capture and Storage projects to a certain extent.

CO2 Leakage Scenarios in Shale Overburden

Potential CO2 leakage from deep geologic reservoirs requires evaluation on a site-specific basis to assess risk and arrange mitigation strategies. In this study, a heterogeneous and realistic numerical model was developed to investigate CO2 migration pathways and uprising time in a shaly overburden, located in the Malaysian off-shore. Fluid flow and reactive transport simulations were performed by TOUGHREACT to evaluate the: (1) seepage through the caprock; (2) CO2-rich brine leakage through a fault connecting the reservoir with seabed. The effect of several factors, which may contribute to CO2 migration, including different rock types and permeability, Fickian and Knudsen diffusion and CO2 adsorption in the shales were investigated. Obtained results show that permeability mainly ruled CO2 uprising velocity and pathways. CO2 migrates upward by buoyancy without any important lateral leakages due to poor-connection of permeable layers and comparable values of vertical and horizontal permeability. Diffusive flux and the Knudsen flow are negligible with respect to the Darcy regime, despite the presence of shales. Main geochemical reactions deal with carbonate and pyrite weathering which easily reach saturation due to low permeability and allowing for re-precipitation as secondary phases. CO2 adsorption on shales together with dissolved CO2 constituted the main trapping mechanisms, although the former represents likely an overestimation due to estimated thermodynamic parameters. Developed models for both scenarios are validated by the good agreement with the pressure profiles recorded in the exploration wells and the seismic data along a fault (the F05 fault), suggesting that they can accurately reproduce the main processes occurring in the system.

Computational fluid dynamics simulation of natural gas hydrate sloughing and pipewall shedding temperature profile: Implications for CO2 transportation in subsea pipeline

The continuous flow assurance in subsea gas pipelines heavily relies on the assessment of temperature profile during hydrate sloughing and pipewall shedding caused by hydrates, with similar implications for carbon dioxide (CO2) transportation under hydrate-forming conditions. Hydrate sloughing is the peeling off of some hydrate deposits from the pipeline inner surface. Similarly, pipewall shedding by hydrates involves the direct interaction of hydrates with the pipeline inner surface, resulting in the detachment or removal of hydrate deposits from the pipewall. While sloughing occur within the deposit of hydrates, pipewall shedding is related to direct interaction of the gas phase with the thin layer of hydrates on the pipewall. In this study, a computational fluid dynamics (CFD) simulation approach is employed, using a validated CFD model from the literature for predicting hydrate deposition rates (Umuteme et al., 2022), by applying a subcooling temperature to the pipe wall at hydrates forming condition. We have deduced the presence of hydrates based on the stable temperature profile of natural gas hydrates along the pipeline model. The study shows that the simulated temperature contours align well with the reported hydrate deposition profile in gas pipelines (Di Lorenzo et al., 2018). The conversion of the consumption rate of natural gas to hydrates was achieved using the equation proposed in the literature (Umuteme et al., 2022). Two shear stress regimes have been identified for hydrate sloughing and pipewall shedding in this study, with the latter resulting in higher shear stress on the pipewall. Presently, there is a growing concern regarding the potential leakage of CO2 in pipelines (Lu et al., 2020; Wang et al., 2022; Wareing et al., 2016), which may escalate due to pipewall corrosion caused by hydrates (Obanijesu, 2012). The findings in this research can provide further knowledge that can enhance the safe transportation of CO2 in pipelines under stable hydrate forming conditions.

A framework to simulate the blowout of CO2 through wells in geologic carbon storage

It is important to evaluate the risks associated with CO2 leakage in large scale carbon capture and storage (CCS) projects. Leaky wells are considered a major concern for potential CO2 leakage in geologic carbon storage. The most rapid and spectacular mode of CO2 leakage is the blowout of a CO2 storage well. The Sheep Mountain CO2 blowout in March 1982 is an example of this type of catastrophe wherein several thousand tons of CO2 were released into the atmosphere every day. The blowout was stopped only in early April. In the current work we present a numerical framework to simulate blowouts of CO2 wells accounting for the supercritical-liquid–gas–solid phase transitions of CO2 during the process. It is an in-house finite volume method based code for CO2 transport in open wells, relying on a hybrid Span–Wagner equations of state. We present extensive verification and validation of the code against numerical and experimental data in the literature. When applied to well blowouts, our numerical method is able to identify the locations along the well where CO2 transitions between its different phases. Our simulations show that while the heat transfer between CO2 and the casing has a significant impact on the transient characteristics of the blowout, it does not affect the steady-state leakage rate significantly. We also find that the CO2 leakage rate increases as the total depth of the well increases, with an average leakage rate of 2.09×104 tons per day across all the well depths simulated ranging between 1 km and 3.5 km. Our simulations show that when the temperature and pressure at the well bottom are appreciably lower than the geothermal temperature and hydrostatic pressure at the given depth, CO2 is released as dry ice at the wellhead. The dry ice modeled here has a significant time-averaged mass fraction of 30% at quasi-steady state, and causes rapid fluctuations in the CO2 leakage rate.

Risk evaluation of CO2 leakage through fracture zone in geological storage reservoir

CO2 storage in saline aquifers is an effective way to reduce the emission of CO2 into the atmosphere. The potential leakage problems are the main challenge for CO2 storage projects. However, the quantitative evaluation and analysis of the driving forces for the potential CO2 leakage problems are still lacking. In this paper, a stratified model embedded with a highly-permeable fracture zone was constructed to simulate CO2 leakage in the post-injection period. The acting forces and dimensionless numbers were systematically analyzed, and four stages were defined based on the leakage characteristics. Ultimately, a novel regression model was developed to predict the percentage of secure storage for CO2 at any dimensionless numbers. Results showed four distinct CO2 leakage stages: fast CO2 leakage stage (T1); decreasing CO2 leakage stage (T2); fast water sink stage (T3); and stable countercurrent flow stage (T4). Viscous force, gravity force, and capillary force were the dominant driving forces in turn in the first three stages. A stable countercurrent flow and CO2 leakage were maintained in the last period. In addition, the turning point of the flow pattern was delayed, and Gravity number (Gr) and Bond number (Bo) decreased obviously with the increase of initial pressure gradient. More importantly, most of the leaked CO2 was trapped in riskier forms (i.e. structural and residual trapping), and heavy acidification occurred in the shallow aquifer. The novel regression model showed that the percentage of secure storage could be enhanced by increasing Gr and/or decreasing the Ca. It is suggested that the pressure gradient at the end of injection should be optimized to store more CO2 and decrease the leakage risk simultaneously.

Evaluation of CO 2 sealing potential of heterogeneous Eau Claire shale

Abstract During geological carbon dioxide storage in deep saline aquifers, buoyant CO 2 tends to float upwards in the reservoir overlaid by a low permeable formation called a caprock. Caprocks should serve as barriers to potential CO 2 leakage that can happen through diffusion and permeation through faults, fractures or pore spaces. The leakage through intact caprock would mainly depend on its permeability and CO 2 breakthrough pressure and is affected by the heterogeneities in the material. Here, we study the sealing potential of a caprock from the Illinois Basin – Eau Claire shale, with sandy and clayey fractions distinguished via electron microscopy, grain/pore size analyses and surface area characterization. The direct measurements of permeability of sandy shale provide the values on the order of 10 −15 m 2 , while clayey specimens are three orders of magnitude less permeable. The CO 2 breakthrough pressure under in situ stress conditions is 0.1 MPa for the sandy shale and 0.4 MPa for the clayey counterpart – these values are higher than those predicted by the porosimetry methods performed on the unconfined specimens. Sandy Eau Claire shale would allow penetration of large CO 2 volumes at low overpressures, while the clayey formation can potentially serve as a caprock in the absence of faults and fractures.

Assessing a potential site for offshore CO2 storage in the Weixinan Sag in the northwestern Beibu Gulf Basin, northern South China Sea

AbstractGeologic carbon storage (GCS) activities, especially offshore, are still far insufficient worldwide. Sedimentary basins in the northern South China Sea (nSCS) are identified to be favorable to offshore GCS deployment. This study investigates by numerical reservoir simulations the performance of the Weixinan Sag in the northern depression of the Beibu Gulf Basin (BGB), which is considered the most promising area for CO2 offshore GCS in saline formations. Simulations of CO2 injection at a potential site with a normal fault indicate that the pressure buildup induced by CO2 horizontal injection could penetrate extremely low‐permeability faults or caprock formations. The CO2 plumes under higher injection pressures are more constrained in the horizontal direction and hence appear thicker while CO2 tends to spread out horizontally in conditions of low pressure. The impermeable fault renders the CO2 plume about 200 m smaller in size horizontally. Assuming the presence of a fault with a highly permeable core causes leakage to occur after about 30 years of injection, which accounts for only 0.04% the injected amount. For the vertical‐well injection case, the potential CO2 leakage only accounts for around 0.28% of the injection amount, which is far less than the criterion (i.e., 2%) required to make GCS worthwhile. The storage capacities of the formations are mainly controlled by the depths and thicknesses since both their porosities and permeabilities are comparable. The formation Jiaowei‐2 and Xiayang have the largest and second largest storage capacities, respectively, when using a fully perforated well for vertical injection. The average storage capacity of the studied site is 13.04 kg m−3, which is comparable to that of the formation Xiayang. Average injectivities of formations Jiaowei‐2, Xiayang, Weizhou‐1, and Weizhou‐3 are 8.29 × 10−5, 1.75 × 10−4, 6.58 × 10−5, and 2.99 × 10−3 kg s−1 Pa−1, respectively. © 2022 The Authors. Greenhouse Gases: Science and Technology published by Society of Chemical Industry and John Wiley & Sons Ltd.

Nano- to macro-scale structural, mineralogical, and mechanical alterations in a shale reservoir induced by exposure to supercritical CO2

Considering the importance of carbon neutrality, UCCUS which is underground carbon capture, utilization, and storage has been widely adopted to mitigate climate change. Studies are being conducted to improve this process, however, there is still a lack of knowledge on the multiscale physicochanical alterations that the storage reservoirs may endure due to the long-term exposure to supercritical CO2 (ScCO2). These changes happen from nano- to macro-scale in mineralogy and pore structures which will impact mechanical and petrophysical attributes of the host rock. Since unconventional shale reservoirs have become the target of CO2-EOR and CO2 storage, it is imperative to understand the long-term impact of these alterations due to ScCO2 exposure. This study coupled experimental and theoretical modeling to investigate continuous nano- to macro-scale changes in mechanical, mineralogical, and structural alterations in the Middle Bakken by exposing samples to ScCO2 for 3, 8, 16, 30 and 60 days. Qualitative analysis of electron micrographs pre and post exposure confirmed certain minerals have evolved while image processing showed a quantitative change in pore structures. Moreover, nanomechanical changes pre and post exposure were inspected via nanoindentation method. Furthermore, we assessed how mineral content was impacted during the exposure using X-ray diffraction analysis. Next, we adopted two rock physics models based on mechanical and mineralogical observations to upscale mechanical properties to the macro scale. Analyses of the results indicate that long-term ScCO2 exposure induces mineral dissolution, precipitation and the development of fractures in the host reservoir. Further, CO2 induced alterations can lead to long-term macro-scale weakening causing a loss in mechanical integrity of the Middle Bakken by decreasing its elastic modulus (DS model = –33 %, MT model = -30 %) and increasing its Poisson’s ratio (DS model = +38 %, MT model = +32 %). Overall, this study can provide new insights for a better design and implementation of UCCUS projects in shale reservoirs, most especially in the Middle Bakken and other similar formations, where a lack of understanding of these variations and project planning could lead to potential CO2 leakages and environmental hazards.

Impact of Supercritical CO2 on Shale Reservoirs and Its Implication for CO2 Sequestration

Hydraulic fracturing has transformed the international energy landscape by becoming the go-to method for the exploitation of natural gas from unconventional shale reservoirs. However, in the recent years, the search for an alternative method of shale-gas exploration has intensified, because of various problems (e.g., contamination of ground and surface water, overexploitation of precious water resources, air pollution, etc.) associated with the usage of water-based fracturing techniques. The use of CO2 for shale gas exploitation has emerged as a better alternative to aqueous-based gas exploration techniques. CO2 when injected into deep shale reservoirs, transitions into supercritical CO2 (SC-CO2) when temperature and pressure condition exceeds the critical point, i.e., 31.1 °C and 7.38 MPa. In this paper, we comprehensively review the impact of SC-CO2 on shale gas reservoirs during the different stages of shale-gas exploration, i.e., (i) drilling, which involves the superiority of SC-CO2 over water-based drilling fluids, in terms of achieving under-balanced well condition, higher rates of penetration, and resistance to formation damage; (ii) fracturing, which involves factors affecting the tortuosity of fractures created by SC-CO2 fracturing, breakdown pressure, and proppant-carrying capacity; and (iii) injection, which involves the twin-headed benefit of enhanced recovery due to CO2/CH4 competitive adsorption and geological sequestration, CO2 vs CH4 excess sorption as a function of pressure, etc. Several research works have indicated discrepancies on how SC-CO2 impacts different shale properties. Some studies show low-pressure N2-gas-adsorption-derived surface area and total pore volume to be increasing with SC-CO2 imbibition, while others show a decreasing trend for the same. Similarly, for some shales, the quartz content, along with the clay mineral contents, decreased as the exposure to SC-CO2 increased, while in some other studies, with similar long-term exposure to SC-CO2, the quartz content was observed to increase along with the decrease in clay content and vice versa. Essentially, the increased exposure to SC-CO2 results in the dissolution of primary porous structures and fractures, and reformation of newer porous structure and conduits in shales. Nonetheless, these changes in the mineralogy weaken the microstructure of the rock bringing significant changes in the mechanical properties of the shales with implications on the wellbore stability and fracturing efficiency. The mechanical properties such as uniaxial compressive strength (UCS), Young’s modulus, and tensile strength decrease as the SC-CO2 saturation period increases. However, some studies have shown factors like bedding angle and phase-state of CO2 having varying effect on the strength behavior of the shales. Moreover, changes in the structure of shales caused by the creation of fractures and the reduction of their strength can also pose major risks, because of potential leakage of CO2 through these created pathways. How these processes would interact at field scale would control the sealing capacity, especially at field-scale for addressing long-term seepage of CO2.

Synergistic effects of CO2 density and salinity on the wetting behavior of formation water on sandstone surfaces: Molecular dynamics simulation

Reservoir wettability is very important to predict the structure and residual capture capacity, potential CO2 leakage accidents and improve the risk assessment and sequestration safety during CO2 geological sequestration. The wetting behavior of fluid on reservoir rock surface is actually an interface phenomenon caused by the interaction of different fluid molecules on rock surface. At present, it is difficult for laboratory experiments to observe the microscopic interface phenomena at the molecular scale under reservoir conditions, while molecular dynamics simulations can characterize the microscopic changes in wetting behavior and analyze the interaction between the fluid and the rock surface. In this study, molecular dynamics simulations are used to study the effects of different CO2 densities and different salinities on the wetting behavior of formation water on the sandstone surface during CO2 geological sequestration. The results show that both salinity and CO2 density have significant effects on the wettability of quartz surfaces. However, the increase in salinity can only weaken the wettability, while the increase in CO2 density can transform the wettability of the quartz surface. Both CO2 molecules and H2O molecules form two adsorption layers at 3.5 Å and 6.9 Å away from the quartz surface. CO2 molecules will replace the positions originally occupied by water molecules on the quartz surface, reducing the contact area between water droplets and the quartz surface. The CO2 density mainly affects the interface behavior between the components in the system, while the NaCl concentration mainly affects the interaction between H2O molecules and ions in the system. The research results can further improve the understanding of the wettability of fluid on the pore surface of reservoir rocks during CO2 geological sequestration.

Underground sources of drinking water chemistry changes in response to potential CO2 leakage

The purpose of this study was to quantify changes to underground sources of drinking water (USDW) quality in response to potential CO2 leakage from geologic CO2 sequestration (GCS) reservoirs. We developed a framework of combined laboratory experiments and reactive transport simulations and used this framework to evaluate the Ogallala aquifer overlying the Farnsworth Unit (FWU), an active GCS site, as a case study. Using chemical reaction parameters obtained from laboratory experiments and numerical simulations, site-specific mechanisms of CO2-water-sediment interactions at the USDW aquifer were interpreted. Long-term risks of potential CO2 leakage were then evaluated with field-scale numerical models using the regional hydrogeological characteristics and reaction parameters obtained from our experiments and simulations. Results suggest that carbonate mineral impurity and cation exchange are key mechanisms for interactions between CO2 and the aquifer sediment. Additionally, for a large leakage rate of 0.1 % injection from one leaky well, the leakage plume might impact an area of 300 m in diameter and significantly affect the local water quality by changing pH and cation concentrations (e.g., Zn, Ba and Sr). After leakage ceases, the zone of impacted fluids would not migrate significantly in subsequent decades due to a low regional groundwater flowrate (for this case study). The relatively small area of impact might not be detected in a monitoring well given the broader spacing in a typical field scenario. Effective early leakage detection may require additional tools, e.g., borehole CO2 movement, four-dimensional seismicity, CO2 soil flux, samples from deeper aquifers, etc., to ensure effective leakage detection and long-term safety of GCS projects.

Tracing CO2 leakage and migration using the hydrogeochemical tracers during a controlled CO2 release field test

A critical environmental issue in carbon capture and storage (CCS) is potential CO2 leakage, which accompanies geochemical reactions with aquifer materials. To investigate the hydrogeochemical effects of CO2 leakage on shallow groundwater at the early stage of CO2 leakage and to evaluate a hydrochemical or isotopic tracer for CO2 migration, a controlled CO2 release experiment was performed in a siliciclastic aquifer at the Environmental Impact Evaluation Test (EIT) site, South Korea. After the baseline survey of hydrochemical and carbon isotope (δ13CDIC) compositions, CO2-infused water was injected at a rate of 5.5 m3/day for 26 days at ∼22 m below ground level in the ∼40 m thick heterogeneous aquifer whose pressure gradient was increased to approximately 10 times the natural gradient to make a flow path along monitoring wells. The arrival of CO2 plume was determined at each monitoring well by the decrease in pH and the increase in the partial pressure of CO2 (PCO2) and EC. δ13CDIC decreased at the arrival of CO2 plume and showed high correlations with log PCO2 since the δ13CDIC of injected CO2 (−24.7‰) was distinct from that of ambient groundwater (−16.7‰) and little carbon sources existed in the aquifer. The spatial and temporal evolution of hydrochemical and isotopic compositions observed using a monitoring well network indicated that the CO2 plume migrated along a preferential pathway overwhelming induced pressure gradient due to water table mounding at injection and that the plume sank to some degree probably due to its large density. Concentrations of hydrochemical elements displayed three types of behavior: (1) pulse-like with rapid increases at the arrival of CO2 plume and decreases despite the continuous injection of CO2 similar to EC (HCO3, Ca, Mg, Na, K, Sr, and Ba), (2) pH dependent with relatively slow increases and decreases in concentrations (SiO2 and Mn), and (3) rapid increases but slow decreases (Li). The hydrochemical variations indicated the dissolution of a limited amount of reactive minerals such as calcite, followed by cation exchange at the early stage of CO2 leakage in siliciclastic aquifers. Based on the study result, Li was an effective hydrogeochemical tracer to monitor the migration of CO2 in siliciclastic aquifers as well as pH, EC, and δ13CDIC.

Simulation of carbon dioxide mineralization and its effect on fault leakage rates in the South Georgia rift basin, southeastern U.S.

Over the past few decades, measured levels of atmospheric carbon dioxide have substantially increased. One of the ways to limit the adverse impacts of increased carbon dioxide concentrations is to capture and store it inside Earth's subsurface, a process known as CO2 sequestration. The success of this method is critically dependent on the ability to confine injected CO2 for up to thousands of years. Establishing effective maintenance of sealing systems of reservoirs is of importance to prevent CO2 leakage. In addition, understanding the nature and rate of potential CO2 leakage related to this injection process is essential to evaluating seal effectiveness and ultimately mitigating global warming.In this study, we evaluated the impact of common chemical reactions between CO2 and subsurface materials in situ as well as the relationship between CO2 plume distribution and the CO2 leakage within the seal zone that cause mineralization. Using subsurface seismic data and well log information, a three-dimensional model consisting of a reservoir and seal zones was created and evaluated for the South Georgia Rift (SGR) basin in the southeastern U.S. The Computer Modeling Group (CMG, 2017), was used to model the effect of CO2 mineralization on the optimal values of fault permeability permeabilitydue to fluid substitution between the formation water and CO2. The model simulated the chemical reactions between carbon dioxide and mafic minerals to produce stable minerals of carbonate rock that form in the fault. Preliminary results show that CO2 migration can be controlled effectively for fault permeability values between 0.1-1 mD. Within this range, mineralization effectively reduced CO2 leakage within the seal zone.