Search Results (14)

Carbon dioxide (CO₂) geosequestration is a critical technology for reducing greenhouse gas emissions, with shale caprocks, such as Opalinus Clay (OPA), serving as essential seals to prevent CO₂ leakage. This study employs computational fluid dynamics and finite element analysis to investigate the hydromechanical behavior of OPA during CO₂ injection, integrating qualitative and quantitative insights. Validated numerical models indicate that capillary forces are the most critical factor in determining the material’s reaction, with an entry capillary pressure of 2–6 MPa serving as a significant threshold for CO₂ breakthrough. The numbers show that increasing the stress loading from 5 to 30 MPa lowers permeability by 0.3–0.45% for every 5 MPa increase. Porosity, on the other hand, drops by 9.2–9.4% under the same conditions. The OPA is compacted, and axial displacements confirm numerical models with an error margin of less than 10%. Saturation analysis demonstrates that CO₂ penetration becomes stronger at higher injection pressures (8–12 MPa), although capillary barriers slow migration until critical pressures are reached. These results demonstrate how OPA’s geomechanical stability and fluid dynamics interact, indicating that it may be utilized as a caprock for CO₂ storage. The study provides valuable insights for enhancing injection techniques and assessing the safety of long-term storage. 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

CO₂–water–rock interactions have an important impact on the stability and integrity of the caprock in CO₂ geological storage projects. The injected CO₂ in the reservoir enters the caprock via different mechanisms, leading to either the dissolution or precipitation of minerals. The mineral alterations change the porosity, permeability, and mechanical properties of the caprock, affecting its sealing capability. To evaluate the sealing effectiveness of overlying caprock and identify the influencing factors, numerical simulations and experiments were carried out on the mudstone Dongying Formation in Dezhou, China. Based on high-temperature and high-pressure autoclave experiments, batch reaction simulations were performed to obtain some key kinetic parameters for mineral dissolution/precipitation. Then, they were applied to the following simulation. The simulation results indicate that gaseous CO₂ has migrated 7 m in the caprock, while dissolved CO₂ migrated to the top of the caprock. Calcite is the dominant mineral within 1 m of the bottom of the caprock. The dissolution of calcite increases the porosity from 0.0625 to 0.4, but the overall porosity of the caprock decreases, with a minimum of 0.054, mainly due to the precipitation of montmorillonite and K-feldspar. A sensitivity analysis of the factors affecting the sealing performance of the caprock considered the changes in sealing performance under different reservoir sealing conditions. Sensitivity analysis of the factors affecting the sealing performance of the caprock indicates that the difference in pressure between reservoir and caprock affects the range of CO₂ transport and the degree of mineral reaction, and the sealing of the caprock increases with the difference in pressure. Increasing the initial reservoir gas saturation can weaken the caprock’s self-sealing behavior but shorten the migration distance of CO₂ within the caprock. When the content is lower than 2%, the presence of chlorite improves the sealing performance of the caprock and does not increase with further chlorite content. This study elucidates the factors that affect the sealing ability of the caprock, providing a theoretical basis for the selection and safety evaluation of CO₂ geological storage sites. Full article

The increasing level of anthropogenic CO₂ in the atmosphere has made it imperative to investigate an efficient method for carbon sequestration. Geological carbon sequestration presents a viable path to mitigate greenhouse gas emissions by sequestering the captured CO₂ deep underground in rock formations to store it permanently. Geochemistry, as the cornerstone of geological CO₂ sequestration (GCS), plays an indispensable role. Therefore, it is not just timely but also urgent to undertake a comprehensive review of studies conducted in this area, articulate gaps and findings, and give directions for future research areas. This paper reviews geochemistry in terms of the sequestration of CO₂ in geological formations, addressing mechanisms of trapping, challenges, and ways of mitigating challenges in trapping mechanisms; mineralization and methods of accelerating mineralization; and the interaction between rock, brine, and CO₂ for the long-term containment and storage of CO₂. Mixing CO₂ with brine before or during injection, using microbes, selecting sedimentary reservoirs with reactive minerals, co-injection of carbonate anhydrase, and enhancing the surface area of reactive minerals are some of the mechanisms used to enhance mineral trapping in GCS applications. This review also addresses the potential challenges and opportunities associated with geological CO₂ storage. Challenges include caprock integrity, understanding the lasting effects of storing CO₂ on geological formations, developing reliable models for monitoring CO₂–brine–rock interactions, CO₂ impurities, and addressing public concerns about safety and environmental impacts. Conversely, opportunities in the sequestration of CO₂ lie in the vast potential for storing CO₂ in geological formations like depleted oil and gas reservoirs, saline aquifers, coal seams, and enhanced oil recovery (EOR) sites. Opportunities include improved geochemical trapping of CO₂, optimized storage capacity, improved sealing integrity, managed wellbore leakage risk, and use of sealant materials to reduce leakage risk. Furthermore, the potential impact of advancements in geochemical research, understanding geochemical reactions, addressing the challenges, and leveraging the opportunities in GCS are crucial for achieving sustainable carbon mitigation and combating global warming effectively. Full article

The integrity of caprock sealing is a crucial factor in guaranteeing the safety and long-term feasibility of CO₂ saline aquifer storage. In this study, we identified three principal mechanisms that give rise to topseal failure: (1) gradual CO₂ seepage through the upper cap, (2) capillary seal failure resulting from the pressure increment due to CO₂ injection, and (3) localized overpressure causing cap rupture. Through the integration of numerical simulation and geomechanics, this study offers a sealing assessment for the caprock. The thorough analysis of the sealing performance of the Guantao formation reveals that after 2000 years of CO₂ injection, the caprock would undergo intrusion by 35 m without any leakage risk. Moreover, investigations into CO₂–water–rock interactions suggest that precipitation reactions outweigh dissolution reactions, leading to a decreased permeability and an enhanced sealing performance. The most likely fracture mode identified is shear fracture with a critical caprock fracture pressure of 36.48 MPa. In addition to these discoveries, it is significant to consider ongoing research aimed at enhancing our ability to predict and manage potential risks associated with carbon capture and storage technologies. Full article

Shear wave velocity (Vs) has significant applications in geoengineering investigations. With the ongoing rise in carbon capture and storage (CCS) initiatives, the role of Vs in monitoring the CO₂ sequestration sites is escalating. Although many studies have been conducted to assess CCS-induced risks, no inclusive research has been conducted integrating those investigations. This study strives to collate and integrate the applications of Vs in geoscience with an emphasis on CCS risk assessment. Based on this research, major CCS-induced risks were detected: induced seismicity, caprock failure, groundwater contamination, fault reactivation, and reservoir deformation. These risks were inclusively described, and the mathematical formulations incorporating the Vs parameter in risk analysis were elaborated. It was concluded that Vs applications can be further extended in monitoring CO₂ plume migration, optimizing CO₂ injection pressures, preventing shallow water contamination, and predicting CCS-induced seismic events. All these applications require fully coupled hydromechanical analysis based on poroelasticity theory. Hence, various factors including pore pressure, in situ stresses, faults distribution, and poroelastic parameters must be carefully determined before the CO₂ injection phase. The mathematical formulations presented in the present study are quite applicable for granting the safety and long-term success of subsurface carbon sequestration. Full article

Underground Hydrogen Storage (UHS) provides a large-scale and safe solution to balance the fluctuations in energy production from renewable sources and energy consumption but requires a proper and detailed characterization of the candidate reservoirs. The scope of this study was to estimate the hydrogen diffusion coefficient for real caprock samples from two natural gas storage reservoirs that are candidates for underground hydrogen storage. A significant number of adsorption/desorption tests were carried out using a Dynamic Gravimetric Vapor/Gas Sorption System. A total of 15 samples were tested at the reservoir temperature of 45 °C and using both hydrogen and methane. For each sample, two tests were performed with the same gas. Each test included four partial pressure steps of sorption alternated with desorption. After applying overshooting and buoyancy corrections, the data were then interpreted using the early time approximation of the solution to the diffusion equation. Each interpretable partial pressure step provided a value of the diffusion coefficient. In total, more than 90 estimations of the diffusion coefficient out of 120 partial pressure steps were available, allowing a thorough comparison between the diffusion of hydrogen and methane: hydrogen in the range of 1 × 10⁻¹⁰ m²/s to 6 × 10⁻⁸ m²/s and methane in the range of 9 × 10⁻¹⁰ m²/s to 2 × 10⁻⁸ m²/s. The diffusion coefficients measured on wet samples are 2 times lower compared to those measured on dry samples. Hysteresis in hydrogen adsorption/desorption was also observed. Full article

Geological storage is one of the most important measures to reduce carbon emissions. The newly developed oilfield A in the Pearl River Mouth Basin of the South China Sea is associated with a large amount of CO₂ with a purity of up to 95%. Two weakly consolidated sandstone saline aquifers located above the oil reservoir can be used for CO₂ storage, but the CO₂ geochemical reaction characteristics in the aquifers should be investigated clearly, which may cause significant damage to the physical properties of the reservoirs and caprocks of the aquifers. In this paper, static CO₂ geochemical reaction experiments and rock thin section identifications were carried out using drill cuttings and sidewall cores, respectively. A numerical simulation was conducted according to the reactor conditions to explore the equilibrium state of the CO₂ geochemical reaction. Through these studies, the characteristics of the geochemical reaction, its impact on the physical properties of the formation, and the CO₂ storage potential by mineral trapping in the target aquifers were revealed. The results show that the two saline aquifers have similar physical properties. The reservoirs are mostly made up of fine-to-medium-grained sandstones as quartz arenite with a considerable amount of feldspar, which can provide favorable pore space for CO₂ storage, while the caprocks are fine-grained felsic sedimentary rocks that can have a good sealing effect. However, both the reservoirs and caprocks contain a certain amount of carbonate and clay minerals. Mineral dissolution dominates in the CO₂ geochemical reaction process, and more Ca²⁺ and Mg²⁺ is released into the formation water. The theoretical maximum CO₂ mineral trapping capacity in the aquifers is 0.023–0.0538 mol/100 g rock, but due to the dynamic equilibrium of the geochemical reaction, the amount of mineralized CO₂ in most of the rock samples is negative, and the average utilization factor is only −55.43%. As a result, the contribution of mineral trapping to the CO₂ storage capacity takes −0.32%, which can be ignored. In the future, it is necessary to conduct detailed research to reveal the effect of a CO₂ geochemical reaction on storage safety, especially in offshore weakly consolidated sandstone saline aquifers, which could be important sites for large-scale CO₂ storage in China. Full article

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. Full article

In any geological subsurface fluid injection, a viable top seal is required to contain the vertical movement of the injected fluid plume. However, seal integrity assessment is challenging because of the uncertainties possessed by various parameters. A probabilistic solution might be more appropriate when significant uncertainties are present. In this study, we evaluate Drake shale caprock structural reliability using a stochastic method. Drake shale is the primary top seal in the Aurora CO₂ storage site, located in the Horda Platform area in the northern North Sea. Based on the lithological variations, Drake caprock shale is divided into two parts designated by upper and lower units. Six model scenarios from the upper and lower Drake units have been tested. The probabilistic structural failures of varying model scenarios are estimated using the First-Order Reliability Method (FORM). Drake Formation shale shows a considerably low probability of failure (~0) with a high reliability index in the initial stress-state condition and after-injection scenarios. Moreover, the parameter sensitivity study indicates that horizontal stress and cohesion are the most influential input parameters during reliability estimation. Comparative analysis between the caprock properties and failure probability reveals that rock strength properties such as cohesion and friction angle strongly dictate the probability of failure estimation. Moreover, comparing two caprock shale formations indicates that the structural failure values are not correlatable; hence, a formation-specific failure assessment is recommended. Full article

Three-dimensional numerical models of potential underground storage and compositional simulation are a way to study the feasibility of storing carbon dioxide in the existing geological formations. However, the results of the simulations are affected by many numerical parameters, and we proved that the refinement of the model grid is one of them. In this study, the impact of grid discretization on CO₂ trapping when the CO₂ is injected into a deep saline aquifer was investigated. Initially, the well bottom-hole pressure profiles during the CO₂ injection were simulated using four different grids. As expected, the results confirmed that the overpressure reached during injection is strongly affected by gridding, with coarse grids leading to non-representative values unless a suitable ramp-up CO₂ injection strategy is adopted. Then, the same grids were used to simulate the storage behavior after CO₂ injection so as to assess whether space discretization would also affect the simulation of the quantity of CO₂ trapped by the different mechanisms. A comparison of the obtained results showed that there is also a significant impact of the model gridding on the simulated amount of CO₂ permanently trapped in the aquifer by residual and solubility trapping, especially during the few hundred years following injection. Conversely, stratigraphic/hydrodynamic trapping, initially confining the CO₂ underground due to an impermeable caprock, does not depend on gridding, whereas significant mineral trapping would typically occur over a geological timescale. The conclusions are that a fine discretization, which is acknowledged to be needed for a reliable description of the pressure evolution during injection, is also highly recommended to obtain representative results when simulating CO₂ trapping in the subsurface. However, the expedients on CO₂ injection allow one to perform reliable simulations even when coarse grids are adopted. Permanently trapped CO₂ would not be correctly quantified with coarse grids, but a reliable assessment can be performed on a small, fine-grid model, with the results then extended to the large, coarse-grid model. The issue is particularly relevant because storage safety is strictly connected to CO₂ permanent trapping over time. Full article

Carbon Capture, Utilization and Storage (CCUS) is a method of burying the captured CO₂ into the reservoir and displacement of crude oil from reservoirs, which considers both economy and environmental protection. At present, it is considered as an important means to deal with global climate change. To ensure the safety of the CCUS scheme, it is very important to study the invasion and migration of CO₂ in different types of caprocks. In this paper, we first choose the injection-production method of fixed gas injection rate at the top of the reservoir and constant pressure oil production at the bottom. Secondly, the distribution of porosity and permeability in the caprock is designed, and four types of caprock models are established: homogeneous caprock, layered homogeneous caprock, heterogeneous caprock, and layered heterogeneous caprock. Finally, the intrusion amount and migration characteristics of CO₂ in caprock of four schemes in injection-production stage and burial stage are studied, and comprehensive analysis and evaluation are made in combination with the pressure distribution of caprock. In addition, the oil recovery ratio, geological CO₂ storage, and amount of CO₂ intrusion in caprock under different injection-production parameters in this model are also analyzed. This study provides a scientific basis for the safe operation of CCUS and geological storage of CO₂. Full article

As the demands of tight-oil Enhanced Oil Recovery (EOR) and the controlling of anthropogenic carbon emission have become global challenges, Carbon Capture Utilization and Sequestration (CCUS) has been recognized as an effective solution to resolve both needs. However, the influential factors of carbon dioxide (CO₂) geological storage in low permeability reservoirs have not been fully studied. Based on core samples from the Huang-3 area of the Ordos Basin, the feasibility and influential factors of geological CO₂ sequestration in the Huang-3 area are analyzed through caprock breakthrough tests and a CO₂ storage factor experiment. The results indicate that capillary trapping is the key mechanism of the sealing effect by the caprock. With the increase of caprock permeability, the breakthrough pressure and pressure difference decreased rapidly. A good exponential relationship between caprock breakthrough pressure and permeability can be summarized. The minimum breakthrough pressure of CO₂ in the caprock of the Huang-3 area is 22 MPa, and the breakthrough pressure gradient is greater than 100 MPa/m. Huang-3 area is suitable for the geological sequestration of CO₂, and the risk of CO₂ breakthrough in the caprock is small. At the same storage percentage, the recovery factor of crude oil in larger permeability core is higher, and the storage percentage decreases with the increase of recovery factor. It turned out that a low permeability reservoir is easier to store CO₂, and the storage percentage of carbon dioxide in the miscible phase is greater than that in the immiscible phase. This study can provide empirical reference for caprock selection and safety evaluation of CO₂ geological storage in low permeability reservoirs within Ordos Basin. Full article