Long-term Storage Of CO2 Research Articles

Geophysical Monitoring Technologies for the Entire Life Cycle of CO2 Geological Sequestration

Geophysical monitoring of CO2 geological sequestration represents a critical technology for ensuring the long-term safe storage of CO2 while verifying its characteristics and dynamic changes. Currently, the primary geophysical monitoring methods employed in CO2 geological sequestration include seismic, fiber optic, and logging technologies. Among these methods, seismic monitoring techniques encompass high-resolution P-Cable three-dimensional seismic systems, delayed vertical seismic profiling technology, and four-dimensional distributed acoustic sensing (DAS). These methods are utilized to monitor interlayer strain induced by CO2 injection, thereby indirectly determining the injection volume, distribution range, and potential diffusion pathways of the CO2 plume. In contrast, fiber optic monitoring primarily involves distributed fiber optic sensing (DFOS), which can be further classified into distributed acoustic sensing (DAS) and distributed temperature sensing (DTS). This technology serves to complement seismic monitoring in observing interlayer strain resulting from CO2 injection. The logging techniques utilized for monitoring CO2 geological sequestration include neutron logging methods, such as thermal neutron imaging and pulsed neutron gamma-ray spectroscopy, which are primarily employed to assess the sequestration volume and state of CO2 plumes within a reservoir. Seismic monitoring technology provides a broader monitoring scale (ranging from dozens of meters to kilometers), while logging techniques operate at centimeter to meter scales; however, their results can be significantly affected by the heterogeneity of a reservoir.

Geochemistry in Geological CO2 Sequestration: A Comprehensive Review

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.

Clay mineral mediated dynamics of CO2 hydrate formation and dissociation: Experimental insights for carbon sequestration

Marine sediment-based CO2 sequestration through hydrate formation is a promising approach for long-term CO2 storage. Despite the prevalence of clay minerals in marine sediments, their impact on CO2 hydrate dynamics remains disputed and necessitates validation. This study systematically investigated the effect of clay minerals, specifically Ca-montmorillonite (Ca-mmt) and illite, on CO2 hydrates nucleation, growth, and dissociation in clay suspensions (0–10 wt% concentrations). Clay minerals significantly promoted CO2 hydrate nucleation by providng additional nucleation sites and influencing water distribution through the surface electric field. Ca-mmt exhibited a more pronounced nucleation effect due to stronger hydration ability of Ca2+ increasing nucleation sites and local CO2 concentration. Both clay minerals enhanced CO2 hydrate growth, with concentration-dependent effects that differ between clay types. Ca-mmt exhibited a higher growth rate at lower concentrations (≤1 wt%), but a lower rate at higher concentrations (>1 wt%) due to the stronger swelling and aggregation ability upon water contact. Morphological analysis revealed the clay minerals’ impact on fluid behavior and mass transfer during hydrate growth. During dissociation, clay minerals impeded the process, prolonging overall dynamics. This study highlights the impact of physicochemical disparities between Ca-mmt and illite on CO2 hydrate dynamics, underscoring the importance of these interactions for CO2 sequestration.

Differential mineral diagenetic evolution of lacustrine shale: Implications for CO2 storage

Understanding the differential diagenetic evolution of different lithofacies is essential for assessing the spatial development of shale reservoirs. These insights are crucial in predicting sealing integrity and storage capacity for sequestered CO2. In this study, we examined seven wells from the Cretaceous Qingshankou Formation in the Songliao Basin, China, with vitrinite reflectance (Ro) values ranging from 0.60 % to 1.62 %. Thin section-based petrographic observations, coupled with QEMSCAN analysis, were used to classify the different lithofacies. X-ray diffraction (XRD) analysis of clay minerals, field emission scanning electron microscope (FE-SEM), and energy-dispersive spectrum (EDS) analyses were employed to analyze the mineral textures, pore types, and diagenetic pathways. The results showed that early diagenetic mineral phases include calcite cement (1st phase), framboidal and microcrystalline pyrite, ferroan and non-ferroan dolomite. Intermediate diagenetic mineral phases were marked by illitization of smectite, chlorite formed by chloritization of smectite and alteration of K-feldspar, and the formation of authigenic albite and quartz, calcite cement (2nd phase) and ankerite. Given the higher potential reaction rate of CO2-fluid‑carbonate systems, we propose that the lithofacies dominated by carbonate minerals are not effective for CO2 storage, even in short-term. In contrast, lithofacies rich in feldspar and clay minerals are likely to be more effective for long-term CO2 storage.

Molecular insight into the dual effect of salts: Promoting or inhibiting the nucleation and growth of carbon dioxide clathrate hydrates

Facing the huge gap between the growing CO2 emissions and net-zero emissions target to mitigate global warming, the long-term storage of excess CO2 becomes an intractable issue. Sequestering CO2 in the oceans as clathrate hydrates is a promising solution. Many unanswered questions still exist at the molecular level regarding how ions in seawater kinetically affect the formation of CO2 hydrates, particularly the dual effect: as the concentration rises, salt ions shift from being a promoter of hydrate formation to becoming an inhibitor. Herein, we report the homogeneous nucleation process of CO2 hydrates in saline solutions via molecular dynamics simulations. Consistent with experimental findings, our results show that nucleation is promoted within certain salt concentration ranges; however, the evidence suggests that ions do not act as nucleation sites. Multiple ion-induced variations in the aqueous phase are analyzed, including changes in the mobility, structure, and CO2 solubility. We find that the presence of ions strengthens the hydrophobic interactions among the dissolved CO2 molecules, which are associated with the salting-out phenomenon, accounting for the promoting effect of salts at low concentrations. However, as the salt concentration increases, this advantage is offset, leading to the inhibiting effect at high salt concentrations. We demonstrate that anions are inevitably involved in the construction of the solid hydrate phase. Their presence disrupts the native tetrahedral connectivity of water molecules and imparts negative charges to the solid phase, thereby attracting cations. In addition to advancing our understanding of the intricate interactions among water, guest, and additive molecules to germinate ordered solid structures, these findings can accelerate the development and utilization of sustainable hydrate-based applications.

CO2-brine interactions in anhydrite-rich rock: Implications for carbon mineralization and geo-storage

The utilization of subsurface geologic media for carbon capture and storage through mineralization has been recognized as a reliable approach. However, less attention has been given to anhydrite rock type for CO2 mineralization and storage. Anhydrite-rich rock formations, commonly found in various geological settings, have the potential to serve as natural carbon sinks through the mineralization of CO2. Therefore, this study aims to investigate the mechanisms and potential of anhydrite-CO2-brine interactions for carbon storage. The experimental approach involved exposing anhydrite-rich rock to supercritical CO2-brine environments under varying conditions of fluid composition. Mineral transformation of an outcrop anhydrite-rich rock sample in static reactor under subsurface conditions of elevated temperature (60 °C) and pressure (104 bar), in the absence and the presence of SrCl2 was conduct for a one-month period. Mineralogical and geochemical analyses, including, solution analyses, X-ray fluorescence, X-ray diffraction, micro-computed tomography, and mechanical properties were conducted to examine the changes in the composition and rock structure resulting from the interactions. The experimental reactions revealed that anhydrite undergoes mineral transformation upon exposure to supercritical CO2-saturated brine to form stable minerals including calcite, dolomite, magnesite, and strontianite, which contributes to the potential for long-term storage of CO2 in the subsurface geologic media. The efficiency and extent of carbon mineralization were found to be influenced by brine composition. These findings contribute to the understanding of the potential of these formations for carbon storage, opening avenues for further research and the development of effective carbon capture and storage strategies.

CO2 transport through swelling organic-rich nanoporous media: Insights on gas permeability from coarse-grained pore-scale simulations

Sorption-induced swelling reduces porosity and permeability in porous media, impacting long-term CO2 storage injectivity. This study employs an innovative coarse-grained model to couple fluid flow with sorption-induced solid deformation at the pore-scale. Our model preserves the advantages of molecular dynamics in simulating complex fluid-solid interaction under nano-confinement while extending the time and length scales. Adjusting the gas-solid interaction energy controls solid swelling and gas slippage at pore walls. Gas permeability curves demonstrate a linear decline with the increasing gas-solid interaction energy in both swelling and non-swelling nanoporous media, with the former experiencing a greater drop. Surprisingly, in the regime of weak gas-solid interactions, swelling is not yet initiated and the porosity and permeability of flexible porous media increase, possibly due to gas flow-induced pore throat opening. Nanoporous media with lower initial porosity experience a greater permeability decline during swelling. The relationship between permeability and porosity changes shows a linear increase characterized by different slopes with varying initial porosities. These findings provide valuable insights into the complex interactions among gas transport, solid deformation, and porosity changes in nanoporous media, with implications for understanding and optimizing gas production and CO2 storage in realistic geological environments.

Density-Driven CO2 Dissolution in Depleted Gas Reservoirs with Bottom Aquifers

Depleted gas reservoirs with bottom water show significant potential for long-term CO2 storage. The residual gas influences mass-transfer dynamics, further affecting CO2 dissolution and convection in porous media. In this study, we conducted a series of numerical simulations to explore how residual-gas mixtures impact CO2 dissolution trapping. Moreover, we analyzed the CO2 dissolution rate at various stages and delineated the initiation and decline of convection in relation to gas composition, thereby quantifying the influence of residual-gas mixtures. The findings elucidate that the temporal evolution of the Sherwood number observed in the synthetic model incorporating CTZ closely parallels that of the single-phase model, but the order of magnitude is markedly higher. The introduction of CTZ serves to augment gravity-induced convection and expedites the dissolution of CO2, whereas the presence of residual-gas mixtures exerts a deleterious impact on mass transfer. The escalation of residual gas content concomitantly diminishes the partial pressure and solubility of CO2. Consequently, there is an alleviation of the concentration and density differentials between saturated water and fresh water, resulting in the attenuation of the driving force governing CO2 diffusion and convection. This leads to a substantial reduction in the rate of CO2 dissolution, primarily governed by gravity-induced fingering, thereby manifesting as a delay in the onset and decay time of convection, accompanied by a pronounced decrement in the maximum Sherwood number. In the field-scale simulation, the injected CO2 improves the reservoir pressure, further pushing more gas to the producers. However, due to the presence of CH4 in the post-injection process, the capacity for CO2 dissolution is reduced.

Recent Advances in Geochemical and Mineralogical Studies on CO2–Brine–Rock Interaction for CO2 Sequestration: Laboratory and Simulation Studies

The urgent need to find mitigating pathways for limiting world CO2 emissions to net zero by 2050 has led to intense research on CO2 sequestration in deep saline reservoirs. This paper reviews key advancements in lab- and simulation-scale research on petrophysical, geochemical, and mineralogical changes during CO2–brine–rock interactions performed in the last 25 years. It delves into CO2 MPD (mineralization, precipitation, and dissolution) and explores alterations in petrophysical properties during core flooding and in static batch reactors. These properties include changes in wettability, CO2 and brine interfacial tension, diffusion, dispersion, CO2 storage capacity, and CO2 leakage in caprock and sedimentary rocks under reservoir conditions. The injection of supercritical CO2 into deep saline aquifers can lead to unforeseen geochemical and mineralogical changes, possibly jeopardizing the CCS (carbon capture and storage) process. There is a general lack of understanding of the reservoir’s interaction with the CO2 phase at the pore/grain scale. This research addresses the gap in predicting the long-term changes of the CO2–brine–rock interaction using various geochemical reactive transport simulators. Péclet and Damköhler numbers can contribute to a better understanding of geochemical interactions and reactive transport processes. Additionally, the dielectric constant requires further investigation, particularly for pre- and post-CO2–brine–rock interactions. For comprehensive modeling of CO2 storage over various timescales, the geochemical modeling software called the Geochemist’s Workbench was found to outperform others. Wettability alteration is another crucial aspect affecting CO2–brine–rock interactions under varying temperature, pressure, and salinity conditions, which is essential for ensuring long-term CO2 storage security and monitoring. Moreover, dual-energy CT scanning can provide deeper insights into geochemical interactions and their complexities.

The Science, Engineering, and Validation of Marine Carbon Dioxide Removal and Storage.

Scenarios to stabilize global climate and meet international climate agreements require rapid reductions in human carbon dioxide (CO2) emissions, often augmented by substantial carbon dioxide removal (CDR) from the atmosphere. While some ocean-based removal techniques show potential promise as part of a broader CDR and decarbonization portfolio, no marine approach is ready yet for deployment at scale because of gaps in both scientific and engineering knowledge. Marine CDR spans a wide range of biotic and abiotic methods, with both common and technique-specific limitations. Further targeted research is needed on CDR efficacy, permanence, and additionality as well as on robust validation methods-measurement, monitoring, reporting, and verification-that are essential to demonstrate the safe removal and long-term storage of CO2. Engineering studies are needed on constraints including scalability, costs, resource inputs, energy demands, and technical readiness. Research on possible co-benefits, ocean acidification effects, environmental and social impacts, and governance is also required.

Comparative study of direct solid-gas carbonation and direct aqueous carbonation for carbon capture and storage

Abstract Carbon dioxide (CO2) is a significant contributor to global warming and environmental issues, necessitating the development of practical storage solutions. As an alternative to CO2 storage in subsurface formations, mineral carbonation, which offers long-term CO2 storage and advantages like thermodynamics and energy economy, is gaining popularity. Also, the possible repurposing of carbonated solid waste in the building and construction industry contributes to the reduction of CO2. However, large-scale implementation of natural mineral carbonation remains a challenge. This study investigates the comparative advantages and disadvantages of direct solid-gas and direct aqueous carbonation, two carbon capture and storage (CCS) methods for combating atmospheric CO2 emissions. The research focuses on reaction kinetics, capture efficiency, recovery efficiency, leakage security, and cost-effectiveness. Both methods have the potential to capture CO2 efficiently, but they differ in their effectiveness and feasibility. Direct solid-gas carbonation exhibits higher reaction rates and capture efficiency, while direct aqueous carbonation has lower energy requirements and is easier to implement at ambient temperature and pressure. Further research is essential to fully understand the comparative merits and drawbacks of direct solid-gas and aqueous carbonation and devise strategies to minimize their environmental impact. Furthermore, to ensure economic feasibility, future research should focus on lowering CO2 sequestration costs, increasing the scale of captured CO2 usage in industrial processes, and developing a circular economy by transforming captured CO2 into valuable metal carbonates.

A process-led approach to framing uncertainty and risk in CO 2 storage in the subsurface

Carbon capture and storage (CCS) requires the safe, long-term storage of CO 2 in the subsurface. This challenges subsurface practitioners to build on and adapt many of the techniques and processes developed for hydrocarbon exploration and production to create innovative approaches to assessing CO 2 storage risk and uncertainty. A wide-ranging and integrated understanding of the processes controlling CO 2 behaviour in the subsurface is required to facilitate effective risk identification and characterization. In this paper we explore the different physical processes acting within storage formations and their evolution throughout the injection project life cycle to illustrate key controls on CO 2 plume behaviour and frame risk identification and characterization. An approach applying wide-reaching premortem risk identification coupled with evidence-led uncertainty characterization is described to frame inputs for detailed risk characterization and management activity during early screening of prospects for CO 2 storage.

Influence of the CO2–brine–rock interaction on the plastic zone of sandstone

During the long-term CO2 storage process, the CO2–brine–rock interaction (CBRI) may change the elastic-plastic behaviors of sandstone reservoirs, potentially leading to rock damage and CO2 leakage. A good understanding of the influence of the CBRI on the plastic zone of sandstone is crucial for evaluating the rock fracturing processes. In this paper, three-point bending tests were conducted under both monotonic and cyclic loading conditions, and the digital image correlation technique was used to analyze the elastic and plastic characteristics of the samples. The experimental results showed that the CBRI decreases the yield strength and corresponding crack mouth opening displacement by 25 % and 65%, respectively, thus increasing the probability of fracturing. Additionally, it was found that the CBRI enlarges the plastic zone by about 20 %. The size of the theoretical plastic zone in the sandstone sample for different loads was determined, and the ratio of the plastic zone size in the samples with CO2–brine saturation to that without CO2–brine saturation was found to be about 1.18. Finally, the mesoscale factors affecting the plastic zone size after CO2–brine saturation were analyzed. This study helps to understand the effect of the elastic-plastic behavior of sandstone on reservoir stability during long-term CO2 storage.

Changes in mechanical properties and surface microstructure of shale organic matter after coupling supercritical carbon dioxide with water

Supercritical carbon dioxide (ScCO2) fracturing technology has been increasingly emphasized in the development of unconventional oil and gas resources due to its advantages of anhydrous fabrication of complex seam networks and geological sequestration of CO2. However, previous studies have mostly focused on the geometry, number, and type of inorganic mineral fractures, and rarely paid attention to the changes in the seepage structure within organic matter (OM). To characterize the nanoscale microstructural changes of OM induced by H2O-ScCO2, this study obtained the variation rule of mechanical properties of OM with adsorbed water saturation based on nanoindentation test, and the continuous change of elastic modulus and morphology of the OM in the same region after dry, water-wet, and water-ScCO2 treatments was compared by atomic force microscopy (AFM). Elastic modulus and hardness of OM were calculated by Oliver-Pharr and Hertz methods, and the average roughness, root mean square roughness, and kurtosis were obtained based on 3D morphology. The results showed that elastic modulus and hardness were negatively and nonlinearly correlated with water saturation. Although the AFM-measured elastic modulus of OM microphases of the dry, water-wet, and water-ScCO2-treated shale were all highly discrete and non-homogeneous, they were generally normally distributed, and the mean values of the elastic modulus decreased sequentially. It is determined that water-ScCO2 coupling make OM matrix undergo superimposed dissolution. It is shown that ScCO2 and water synergistically change the microstructure of shale OM, and the weakening of mechanical properties and the increase of surface roughness are very favorable for geological sequestration and long-term storage of CO2.

Geological survey techniques and carbon storage: Optimizing renewable energy site selection and carbon sequestration

Geological survey techniques play a crucial role in optimizing site selection for renewable energy projects and identifying suitable locations for carbon storage to mitigate climate change. This abstract provides an overview of how geological survey techniques can be used to achieve these objectives. Renewable energy development, particularly solar and wind power, requires careful site selection to maximize energy generation efficiency and minimize environmental impacts. Geological surveys are instrumental in assessing factors such as subsurface geology, topography, soil composition, and hydrological conditions. These surveys help identify suitable locations with optimal wind or solar resources and geologic conditions for infrastructure development. Additionally, geological surveys are essential for identifying suitable sites for carbon storage, a critical component of carbon capture and storage (CCS) technologies aimed at reducing greenhouse gas emissions. Geological formations, such as deep saline aquifers, depleted oil and gas reservoirs, and unmineable coal seams, can serve as storage reservoirs for captured carbon dioxide (CO2). Geological surveys help characterize these formations to assess their suitability for long-term CO2 storage, considering factors such as porosity, permeability, and sealing integrity. Optimizing site selection for renewable energy projects and carbon storage requires a comprehensive understanding of subsurface geology and environmental conditions. Advanced geological survey techniques, such as seismic imaging, remote sensing, and geophysical surveys, are essential for acquiring detailed subsurface data. These techniques enable scientists and engineers to assess site suitability, evaluate risks, and design effective mitigation measures. In conclusion, geological survey techniques are invaluable tools for optimizing site selection for renewable energy projects and identifying suitable locations for carbon storage. By leveraging these techniques, stakeholders can make informed decisions that promote sustainable energy development and mitigate the impacts of climate change.

Evolution of shale wetting properties under long-term CO2/brine/shale interaction: Implications for CO2 storage in shale reservoirs

In the case of Carbon Geological Storage (CGS), the wettability is one of the main parameters controlling the CO2 injection capacity and CO2 plume movement, which affects the safety of long-term CO2 storage. A full evaluation of this parameter is essential for risk evaluation and storage capacity estimation. The objective of this study was to investigate the wettability changes of shales from the Chang 7 Formation in the Ordos Basin by exposing the samples to ScCO2/brine for 10/20/30/and 60 days. The mineral composition, pore structure, chemical functional groups, and surface morphology changes of the shale were analyzed using x-ray diffractometer (XRD), low-temperature nitrogen adsorption (LN-N2), infrared spectroscopy (FTIR), and scanning electron microscopy (SEM). In addition, the solid-drop method was used to measure the contact angle of shale samples at different times of ScCO2 soaking. The results show that after 60 days of continuous ScCO2 soaking, the shale water contact angle and chemical group peak spectrum generally show an increasing trend, which is caused by the reduction of carbonate and clay mineral content. The prolonged time of ScCO2 soaking weakens the shale's water wettability and reduces the water-locking effect (water has a sealing effect in the pore channel of the reservoir), capillary force, and the height of CO2 sequestration columns, which is favorable for shale gas extraction (a method of extracting natural gas from shale rock by CO2 fracturing), but it may increase the CO2 geological leakage risk. The results have important implications for regulating the change of shale water wettability, and this study can also better provide theoretical references for Carbon Geological Storage programs.

A review on geological storage of marine carbon dioxide: Challenges and prospects

Carbon capture, utilization, and storage (CCUS) is believed to be the most promising technology to mitigate climate change and global temperature rise. As an effective method for reducing carbon emissions, carbon dioxide (CO2) storage on the seabed can be achieved by injecting captured CO2 from offshore platforms into subsea storage sites, such as the sediment layers, depleted oil and gas reservoirs and deep saline aquifers, thereby permanently removing it from the atmosphere. Additionally, hundreds to thousands of meters of seawater above seabed storage layers provide naturally high seawater pressure and abundant barrier settings that can reduce leakage risk. Consequently, this has become an ideal storage location for long-term CO2 storage. In order to thoroughly investigate the mechanism and potential of marine CO2 storage and promote further development of CCUS, this paper provides a comprehensive description of theoretical research of marine CO2 geological storage, including storage mechanisms, storage capacity, wellbore flow, CO2 migration, cap rocks integrity and CO2 leakage monitoring. The implementation status of global engineering projects is summarized. Currently, there are relatively few successful marine storage projects globally, with the majority of others still in the research and testing stages. Finally, the challenges and prospects of marine CO2 storage are also discussed. This review demonstrates the enormous potential and promising future of marine CO2 storage, but there are also leakage risks. It can be avoided through in-depth theoretical research to clarify the entire process of storage mechanisms and take corresponding technological measures. Ultimately, a new technology for large-scale efficient injection and enhanced storage of marine CO2 storage will be formed.

Machine Learning Provides Fracture Analysis, Mapping for CCUS

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 214996, “Machine-Learning Application for CCUS Carbon Storage: Fracture Analysis and Mapping in the Illinois Basin,” by Guoxiang Liu, SPE, US Department of Energy, and Abhash Kumar and William Harbert, SPE, Contractors, et al. The paper has not been peer reviewed. _ The monitoring of storage reservoirs to ensure safe, long-term storage of CO2 and to derisk operations and storage management is undergoing dynamic shifts, expanding opportunities for implementing innovative techniques and applications, especially for commercial-scale deployment. In the complete paper, a method with multitiered analysis has been developed to leverage advanced machine-learning (ML) techniques to process passive seismic monitoring data acquired during an injection period along with pumping/injection pressure and rate in the Illinois Basin for potential fracture and fault analysis. Introduction This study is part of the Science-Informed ML for Accelerating Real-Time Decisions in Subsurface Applications (SMART) Initiative funded by the US Department of Energy Carbon Storage Program. The outcomes of the SMART Initiative are science-informed, ML-based tools that can be applied at carbon storage sites throughout the nation and the world to achieve the following objectives: - Improve the ability to consolidate technical knowledge, site-specific characterization information, and real-time data in a digestible way - Enable the optimization of carbon-storage reservoirs by creating a capability for real-time forecasting of the behavior of such reservoirs - Improve the ability to understand and communicate subsurface behavior during carbon-storage operations to nonexperts Methodology In the authors’ study, a multitiered, data-driven approach was created by integrating all available measurement data to visualize fracture networks. The data sets included measurements from drilling, log and core testing, injection and downhole pressure measurements, and five vertical-pressure-monitoring gauges, providing a wealth of detail on the fracture networks. A fracture network encompasses natural fractures, induced or hydraulic fractures, and the dynamic response of such fractures, culminating in a comprehensive understanding of this system. Because of the wide range of resolutions and scales of the data sets, the fracture network was mapped into 19 distinct time windows over a 3-year injection period by analyzing pumping data, which included CO2 injection and bottomhole pressure. Passive seismic data (microseismic) were compartmentalized into these time windows, similar to the industry practice of compartmentalizing microseismic data into separate stages for high-pressure fluid- injection activities (i.e., induced fracturing). In each of these time windows, the b-value of the associated microseismic population was estimated. Furthermore, event-occurrence time and distance from the treatment well were used to identify the distinct triggering front of microseismicity likely associated with pre-existing fractures and faults within the reservoir. Seismogenic b-value and diffusivity analyses were applied to identify triggered fronts for further clustering and fracture-plane and 3D fracture-distribution analysis. The potential of several unsupervised ML algorithms was leveraged to identify the spatial clusters of microseismic events within each triggering front of individual time windows by following the work flow described in Fig. 1 of the complete paper. Furthermore, these ML techniques were implemented to determine the best-fitting surface for each spatial cluster of microseismicity to infer the directional and spatial distributions of fractures.

Carbon Storage Potential of Shale Reservoirs Based on CO2 Fracturing Technology

The development of shale reservoirs is important in ensuring China’s national energy security by achieving energy independence. Among the key technologies for shale oil production, CO2 fracturing is an effective method that can not only enhance oil recovery but also promote large amounts of CO2 storage, thereby supporting China’s goals of achieving a carbon peak and carbon neutrality. This research paper aims to study the impacts and prospective applications of CO2 fracturing in shale reservoirs, using real exploitation parameters from the GYYP1 well in the Songliao Basin. By utilizing numerical simulation, the dynamics of CO2 production are analyzed. Adsorption and diffusion are identified as pivotal mechanisms for CO2 storage in shale reservoirs. After the analysis of the fracturing process, approximately 22.13% of CO2 is found to be adsorbed, which decreases to 11.06% after ten years due to pressure decline. Diffusion increases the volume of CO2 interacting with a greater extent of shale, thereby enhancing the adsorption mechanism. Over time, the diffusion process results in a remarkable increase of 26.02% in CO2 adsorption, ensuring the long-term and stable storage of CO2 within the shale reservoir. This investigation delves into the contribution of these two crucial mechanisms of CO2 storage in shale reservoirs, ultimately predicting that, by 2030, approximately two million tons of CO2 can be effectively stored in the Daqing Oilfield through CO2 fracturing in shale oil reservoirs. Such an achievement will undoubtedly contribute to the sustainable development of the energy sector and foster the transformation and upgrading of China’s energy structure.

Assessing the potential for CO2 storage in shallow coal seams using gas geochemistry: A case study from Qinshui Basin, North China

Shallow coal seams are a target reservoir for CO2 sequestration. So far efforts to trace CO2 sequestration by coal beds have largely focussed on short-term monitoring or theoretical modelling. To evaluate the feasibility of safe long-term storage of CO2 in shallow coal beds, we report the first systematic gas geochemical study at a shallow injection site in Shizhuang, Qinshui Basin, one year after CO2 injection ceased. The injected CO2 is isotopically distinctive and appears to be enriched in heavy noble gases (Kr and Xe). The high CO2 content and light δ13CCO2 of gases from production wells confirm the migration of injected gas to the northeast and east of the main injection well previously tracked by geophysical studies. The migration of injected gas to the southeast has not been identified before, and exceeds that to the northeast, implying that gas geochemistry provides a more robust method of tracking migration. Less than 1 % of the total injected CO2 has been extracted from production wells in the year since injection ceased. We estimate that the target coal seam in the study area can store about 0.08 billion tonnes of CO2. Scaling up we estimate that the Qinshui Basin has the potential to store about 19 billion tonnes of CO2. This is significantly more than previous estimates. This study demonstrates the importance of geochemical tracers in quantifying and monitoring CO2 sequestration and also implies that unmined coal seams have high potential for the long-term storage of CO2.