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The US DOE-funded National Risk Assessment Partnership (NRAP) has developed an integrated assessment model (NRAP-IAM-CS) that can be used to simulate carbon dioxide (CO2) injection, migration, and associated impacts at a geologic carbon storage site. The model, NRAP-IAM-CS, incorporates a system-modeling-based approach while taking into account the full subsurface system from the storage reservoir to groundwater aquifers and the atmosphere. The approach utilizes reduced order models (ROMs) that allow fast computations of entire system performance even for periods of hundreds to thousands of years. The ROMs are run in Monte Carlo mode allowing estimation of uncertainties of the entire system without requiring long computational times. The NRAP-IAM-CS incorporates ROMs that realistically represent several key processes and properties of storage reservoirs, wells, seals, and groundwater aquifers. Results from the NRAP-IAM-CS model are used to quantify risk profiles for selected parameter distributions of reservoir properties, seal properties, numbers of wells, well properties, thief zones, and groundwater aquifer properties. A series of examples is used to illustrate how the risk under different storage conditions evolves over time, both during injection, in the near-term post injection period, and over the long term. It is also shown how results from NRAP-IAM-CS can be used to investigate the importance of different parameters on risk of leakage and risk of groundwater contamination under different storage conditions.

AbstractOne of the largest storage potential for CCS is in the deep saline aquifers because their pore water cannot be used for drinking and for agricultural activities. In the Pannonian Basin (Hungary) there are sedimentary sub-basins filled up by sedimentary rock sequences containing such aquifers, which have the main potential for CCS in Hungary. Our chosen study area in the Pannonian Basin was the Jászság Subbasin, well known by numerous seismics and hydrocarbon exploration wells. As Hungary is situated in the middle of the Pannonian Basin, its emissions could be significantly reduced by CCS. That is the main reason to find a suitable place for CCS.The process filling up the basin resulted in a sedimentary system from deep-water to deltaic sediments, including thick facies units of reservoir quality as well as thick facies units acting as seals above it. During the evolution of the basin, large rivers brought huge amounts of sediments from the NE and NW towards the deeper parts of Lake Pannon, forming huge deltas on the river mouths.The potential reservoir formations now form a hidrogeologically coherent regional system, indicating a large potential for storage capacity. Furthermore, the saline aquifer system is large enough to ensure its long-term industrial usage for CCS, because the injection does not cause critical increase in the pressure. However, the system is not homogenous: there are siltstone interbeddings both in the Algyő (clayey cover formation), and the Szolnok Formations (dominantly sandstone), as we could see on well-logs of HC exploration wells. The siltstone in these formations does not have porosity high enough to be the storage rock, whereas the permeability is not low enough to be a good cap rock. That is why we try to avoid sampling siltstone-rich regions in the whole Jászság Basin. On the other places, and depth intervals we have used drilling cores to get a realistic quality and representative quantity of the tested formations.Our detailed studies deal with the sandy Szolnok Formation, and the clayey Algyő Formation. The Szolnok Fm. is mainly formed by sandstone, its bottom is nearly 1000 to 3500 m deep under the surface, thus it would be used as a storage rock. Its cap rock (seal) is the Algyő Fm. with more than 1000 m thickness, and a clayey composition.These potential rock associations are examined in detail in our ongoing research. We will do ex situ tests observing the behavior of the rocks when injecting supercritical CO2 in the saline pore water on pressure and temperature representing the depth of planned injection conditions.

AbstractThe migration of CO2 stored in deep saline aquifers depends on the morphology of the top of the aquifer. Topographical highs, such as anticlines, may trap CO2 and limit the distance migrated, or elevated ridges may provide pathways enabling CO2 to migrate further from the injector. For example, seismic data of the Utsira formation at the Sleipner storage site indicates that a branch of the CO2 plume is moving to the north [1]. It is therefore important to study the interface between the aquifer and the caprock when assessing risk as CO2 storage sites.Undulations in the top surface of an aquifer may either be caused by sedimentary structures [2], or by folding. In addition, irregularities may be generated by faulting [2]. Large-scale features are detected using seismic data (i.e. structures with amplitudes greater than 10 m), and such structures will generally be included in reservoir or aquifer models. However, smaller- scale features could also have an effect on a CO2 plume migration, and this is the topic of our study. We have conducted simulations in models with a range of top-surface morphology, and have examined the distance migrated and the amount of dissolution.The results from this study suggest that the effects of sub-seismic variations in the topography of the aquifer/caprock interface are unlikely to have a significant impact on the migration and dissolution of CO2 in a saline aquifer, compared with tilt or permeability anisotropy. The results were most sensitive to the kv/kh ratio during the injection period.

AbstractMethodologies for the basin-scale evaluation of industrial-scale CO2 geological storage in saline aquifers can include the use of analytical tools, generic reservoir simulations, as well as basin-specific flow modelling studies. The selection of appropriate tools is dependent on the scale of investigation. Comparison of the results from these methods for the assessment of basin-scale CO2 geological storage in the Gippsland and Otway basins in Australia suggests that, at this scale, a combination of analytical tools in the form of equations for calculating injection pressure, radius of impact and storage capacity with generic numerical simulations may provide useful first-order predictions for storage capacity and injectivity. However, the development of multiple resources (petroleum, groundwater, coal) in the Gippsland Basin and regional compartmentalisation in the Otway Basin necessitates an additional, coarsely discretised basin-scale numerical model.

AbstractInjection of CO2 in geological formations is widely recognized as a promising technology within the set of strategies to be developed to reduce the concentration of atmospheric CO2. The management of long-term safety related with Geological Storage of CO2 (CGS) should be an iterative and interactive on-going improvement process throughout the life of the project. This process, through application of appropriate methodologies, should establish a robust and reliable framework for identifying, assessing and managing each project phase. It plays a key role in both the definition and planning of CO2 injection strategies at any scale and in its operational, closure and post-closure stages.A key element to calculate the probability of leakage risk includes the interaction of the CO2 plume with potential flow paths or with risk elements. This requires obtaining the temporal evolution of the injected CO2 plume (dynamic probability). Sufficient understanding of the CO2 plume migration within the reservoir is essential to assess the risks of leakage for different injection scenarios. The stochastic simulation can be a valuable tool to achieve a sufficient understanding of the underlying mechanisms that control the behaviour of a system. However, it is not uncommon that using probabilistic modelization to make predictions of future behaviour of a system (predictive modelization) turns out to be a complex process. The CO2 plume evolution and structural and hydrodynamic trapping mechanisms are key elements in the safety of a site. These are determined by the number of gravity, Γ, a dimensionless parameter that measures the ratio between buoyancy and viscous forces, and which is defined from both operating and reservoir parameters and, among others, is a function of the injection rate.The models used in this work are based on published studies on CO2 injection from a single well into a deep permeable aquifer saturated with saline fluid (saline aquifer). The type of solution obtained is a function of the relationship between buoyancy and viscous forces. According to the injection rate, in viscous forces domain cases it is possible to decouple the petrophysical variables of the system that determine the advance of the plume (porosity and permeability) depending on the shape ratio of the plume (rmin/rmax or ratio between the radii at the bottom and top of the CO2 plume).This is a methodology that makes sense for applying it to the initial stages of characterization of potential CO2 geological storage sites in situations of shortages of data, which it is a common feature of deep saline aquifers. Hontomín site intends to be a demo site for CO2 injection in carbonate formations, these being the probable most promising CO2 geologic storage formation type in Spain. A basic characteristic of these sites is the lack of deep carbonate formations porosity and permeability data, critical variables especially in risk studies. This methodology has its scope in the injection phase for a preliminary characterization, before the start of a possible systematic characterization of the site prior to a potential industrial use. So, a study has been conducted to explore the possibility of using the perturbation of the system by the CO2 injection to get an upscaling of both porosity and permeability en grand of the storage formation from the in situ or laboratory characterization phases through stochastic modelling of the CO2 plume and the appropriate injection strategies within the range of viscous forces domain cases. This provides a reduction of the uncertainties in the calculation and adjustment of dynamic probabilities of both the plume advance and the pressure increase due to the injection of CO2. As a whole it will result in an improvement in the storage safety assessment

AbstractIn this study, numerical simulations are conducted to predict the long-term behavior of CO2 injected into a deep saline aquifer composed of alternating sandstone and shale layers. We carried out a base-case simulation with a conceptual model broadly based on the geological structure underlying the Tokyo Bay area and sensitivity analyses of key parameters. The results show that alternating layers of moderate permeability and capillary pressure without a structural trapping also has considerable capacity of CO2 storage and seal.

AbstractThe CO2 Field Lab project consisted in an injection of 1.7 tons of CO2 at a 20 m depth within a shallow aquifer located in fluvio-glacial deposits. Baseline acquisitions, leakage monitoring and post-injection monitoring were performed in the water phase at different depths (5, 10 and 15 m).Strong deviations of pH, specific conductance or alkalinity were observed and monitored at the horizons affected by the CO2 intrusion. The complex distribution of waters in the ridge deposits not only induced water/rock interactions but also mixing of saline and fresh waters. This points out the complexity of natural environments and the challenge in identifying CO2 leakage from deeper-seated reservoirs.