Modeling of CO2 Leakage up Through an Abandoned Well from Deep Saline Aquifer to Shallow Fresh Groundwaters (original) (raw)
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Modelling and Simulation of Mechanisms for Leakage of CO2 from Geological Storage
Energy Procedia, 2009
For investigation of the risks associated with future geological storage of CO 2 , and for determining the minimum requirements for the quality of geological storage sites, detailed study of possible leakage mechanisms is necessary. Mechanisms for potential leakage from primary CO 2 storage in deep saline aquifers have been studied. A buoyancy-driven flow of CO 2 through a percolating network of permeable bodies in an otherwise sealing cap-rock has been simulated on a geological model of the overburden composed of geological features characteristic for a marine sediments. Channels and lobes from turbidite flows are significant constituents to form a possible leakage pathway in this study.
Geochemical modelling of formation damage risk during CO2 injection in saline aquifers
Journal of Natural Gas Science and Engineering, 2016
This study provides an understanding of the impact of geochemical reactions during and after CO 2 injection into a potential storage site. The results of calculations of geochemical reactivity of reservoir rock and of cap rock during and after CO 2 injection were performed using a geochemical simulator, with the calculations showing that for these conditions up to 0.5 moles of CO 2 can be dissolved per kg of water. The risk of dissolution of primary cements was considered and identified. In addition, the potential of carbonation reactions to permanently sequester CO 2 was considered, although these reactions were shown to be very slow relative to other processes. The implications for security of storage are that while dolomite nodules exist in the sandstone formation, these do not contribute significantly to the overall rock strength, and hence the risk of dissolution of the formation or caprock causing significant leakages pathways is very low. Further calculations were performed using a commercial reservoir simulation code to account for brine evaporation, halite precipitation and capillary pressure re-imbibition. The impact on injectivity was found not to be significant during continuous and sustained injection of CO 2 at a constant rate. Capillary pressure effects did cause re-imbibition of saline brine, and hence greater deposition, reducing the absolute porosity by up to 13%. The impact of the halite deposition was to channel the CO 2 , but for the configuration used there was not a significant change in injection pressure.
Modeling of CO2storage in aquifers
Journal of Physics: Conference Series, 2011
Storage of CO2 in geological formations is a means of mitigating the greenhouse effect. Saline aquifers are a good alternative as storage sites due to their large volume and their common occurrence in nature. The first commercial CO2 injection project is that of the Sleipner field in the Utsira Sand aquifer (North Sea). Nevertheless, very little was known about the effectiveness of CO2 sequestration over very long periods of time. In this way, numerical modeling of CO2 injection and seismic monitoring is an important tool to understand the behavior of CO2 after injection and to make long term predictions in order to prevent CO2 leaks from the storage into the atmosphere. The description of CO2 injection into subsurface formations requires an accurate fluid-flow model. To simulate the simultaneous flow of brine and CO2 we apply the Black-Oil formulation for two phase flow in porous media, which uses the PVT data as a simplified thermodynamic model. Seismic monitoring is modeled using Biot's equations of motion describing wave propagation in fluid-saturated poroviscoelastic solids. Numerical examples of CO2 injection and time-lapse seismics using data of the Utsira formation show the capability of this methodology to monitor the migration and dispersal of CO2 after injection.
International Journal of Greenhouse Gas Control, 2016
A series of batch and column experiments combined with solid phase characterization studies was conducted to evaluate the impacts of the potential leakage of carbon dioxide (CO 2) from deep subsurface storage reservoirs to overlying potable carbonate aquifers. The main objective was to gain an understanding on CO 2 gas-induced changes in aquifer pH and mobilization of major, minor, and trace elements from dissolving minerals in rocks representative of an unconfined, oxidizing carbonate aquifer within the continental US. Samples from the unconfined portion of the Edwards limestone aquifer in Texas were exposed to a CO 2 gas stream or were leached with a CO 2-saturated influent solution simulating different leaking scenarios [i.e., sudden, fast, and short-lived release of CO 2 (batch experiments) and gradual release (column experiments)]. The results from the batch and column experiments confirmed that exposure to excess CO 2 gas caused significant decrease in pH (about two pH units); the release of major chemical elements into the contacting aqueous phase (such as Ca, Mg, Ba, Sr, Si, Na, and K); the mobilization and possible rapid immobilization of minor elements (such as Al and Mn), which are able to form highly reactive secondary phases; and sustained but lowconcentration releases of some trace elements (such as Mo, Cs, Sn) in some samples. Spikes of low concentrations of other trace elements (such as As, Cd, Pb, Cu, Zn, Se, etc.), were observed sporadically during these experiments. The results help in developing a systematic understanding of how CO 2 leakage is likely to influence pertinent geochemical processes (such as dissolution/precipitation and sorption/desorption) in the aquifer sediments and will support site selection, risk assessment, policymaking, and public education efforts associated with geologic CO 2 sequestration.
2020
This work is part of the Aquifer CO2-Leak project and aims to understand, quantify and model the environmental impact of a CO2 leak on water quality in the carbonate freshwater aquifer as well as CO2-water-carbonate interactions. The experiment has been performed within an Oligocene carbonate underground quarry located in Saint-Emilion (France). A water charged with dissolved CO2 was injected in the aquifer through a borehole. Downstream, seven wells were fitted with in-situ probes which automatically measured physicochemical parameters. Periodic water samplings in all wells have been undertaken to determine the elemental concentrations by ion chromatography. The spread of CO2 in the groundwater was monitored as a function of time and was observed to influence the various physicochemical parameters. Five parameters seem to be excellent Manuscript File 2 indicators for monitoring a gas plume during CO2 geological storage in regard to our results: electrical conductivity and pH, and Ca 2+ , HCO3-, and CO2(aq) concentrations. The interaction between CO2 and limestone is highlighted by a saturation index (SI) calculated with PhreeqC software. It shows (i) a slight trend to dissolution of calcite in the injection well (SI<0) linked to the reaction process between CO2-H2O-CaCO3 and (ii) a transport process via diffusion for the observation wells with a SI≃0. The evolution of physicogeochemical signatures in the aquifer allows us to understand the reactive and transport processes that occur during the migration of a gasified water plume in the context of leakage from a geological storage reservoir. Our results will make possible to model a leakage in a complex natural reservoir.
Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles, 2017
This article presents the preliminary results of a study carried out as part of a demonstration project of CO 2 storage in the Paris Basin. This project funded by ADEME (French Environment and Energy Management Agency) and several industrial partners (TOTAL, ENGIE, EDF, Lafarge, Air Liquide, Vallourec) aimed to study the possibility to set up an experimental infrastructure of CO 2 transport and storage. Regarding the storage, the objectives were: (1) to characterize the selected site by optimizing the number of wells in a CO 2 injection case of 200 Mt over 50 years in the Trias, (2) to simulate over time the CO 2 migration and the induced pressure field, and (3) to analyze the geochemical behavior of the rock over the long term (1,000 years). The preliminary site characterization study revealed that only the southern area of Keuper succeeds to satisfy this injection criterion using only four injectors. However, a complementary study based on a refined fluid flow model with additional secondary faults concluded that this zone presents the highest potential of CO 2 injection but without reaching the objective of 200 Mt with a reasonable number of wells. The simulation of the base scenario, carried out before the model refinement, showed that the overpressure above 0.1 MPa covers an area of 51,869 km 2 in the Chaunoy formation, 1,000 years after the end of the injection, which corresponds to the whole West Paris Basin, whereas the CO 2 plume extension remains small (524 km 2). This overpressure causes brine flows at the domain boundaries and a local overpressure in the studied oil fields. Regarding the preliminary risk analysis of this project, the geochemical effects induced by the CO 2 injection were studied by simulating the fluid-rock interactions with a coupled geochemical and fluid flow model in a domain limited to the storage complex. A one-way coupling of two models based on two domains fitting into each other was developed using dynamic boundary conditions. This approach succeeded to improve the simulation results of the pressure field and the CO 2 plume as well as the geochemical behavior of the rock. These ones showed that the CO 2 plume tends to stabilize thanks to the carbonation in calcite and dawsonite and no significant porosity change appears over 1,050 years. The CO 2 mass balance per trapping type gives a CO 2 carbonation rate of about 78% at 1,050 years that seemed to be excessive compared to the simulation study of other storage sites. Thus, an additional work dealing with both the kinetic data base and the textural models would be necessary in order to reduce the uncertainty of the injected CO 2 mineralization.
Numerical simulation of CO 2 geological storage in saline aquifers – case study of Utsira formation
2013
CO2 geological storage (CGS) is one of the most promising technologies to address the issue of excessive anthropogenic CO2 emissions in the atmosphere due to fossil fuel combustion for electricity generation. In order to fully exploit the storage potential, numerical simulations can help in determining injection strategies before the deployment of full scale sequestration in saline aquifers. This paper presents the numerical simulations of CO2 geological storage in Utsira saline formation where the sequestration is currently underway. The effects of various hydrogeological and numerical factors on the CO2 distribution in the topmost hydrogeological layer of Utsira are discussed. The existence of multiple pathways for upward mobility of CO2 into the topmost layer of Utsira as well as the performance of the top seal are also investigated. Copyright © 2014 International Energy and Environment Foundation All rights reserved.
All Days, 2010
Maintaining the long term storage of CO2 is an important requirement for a large scale geologic CO2 storage project. Nevertheless, the possibility remains that the CO2 will leak out of the formation into overlying groundwater aquifers. There are many groundwater remediation technologies available that could be applied for remediating CO2 leaks. A site specific remediation plan is also important during the site selection process and necessary before storage begins. Due to the importance of protecting drinking water resources, this study determines the optimal remediation scenario for various leakage conditions. The two objectives for remediation considered here are removing any mobile CO2 and reducing the quantity of CO2 in the reservoir. The main technique to remediate the leak is to extract the CO2 in both the gaseous and dissolved phase. Another technique analyzed is to inject water to dissolve the gaseous CO2 in the groundwater and reduce the overall aqueous concentration and imm...
Energy Procedia, 2014
A numerical simulation study of CO 2 injection into the Forties and Nelson oilfields to estimate their storage potential is presented in this paper. The estimation involves the consideration of key-performance indicator parameters that include: the pressure buildup for different rates and locations of injection, the regional mass fraction of CO 2 , the volumetric efficiency of the storage reservoirs, and the plume size. Various injection scenarios were compared in terms of these parameters, and the best scenario was identified for the capacity estimation. Potential leakage through the wellbores in the surrounding saline aquifer was also investigated.
Energy Procedia, 2011
To ensure safe behavior during the whole lifetime of the geological storage of CO 2 , site selection and its characterization are essential corner stones. This paper presents the different milestones and the results of each step of the site characterization implemented on a potential storage site in the Triassic deep saline aquifer of the Paris Basin. It addresses a well known theory and practical aspects and challenges of the first phase of real site identification carried out by Veolia Environnement and Geogreen. The initial static and dynamic characterization of the storage complex will mainly rely on available public or proprietary data. Different challenges related to the gathering and validation of existing data are discussed. The characterization methodology should aim at re-interpreting the available data in order to populate a dynamic model at semi-regional scale of the storage complex. 2D Seismic data reprocessing made it possible to determine the local structure of the storage. Regional structural information must also been considered since industrial scale injection impacts a significant area with respect to overpressure extension. To complete the storage complex description, upper laying structures and aquifers must be adequately described up to the ground level. When elaborating such a 3D model, data consistency at the different scales should be carefully checked. Facies variations, porosity and both vertical and horizontal permeabilities will control storage capacity and well injectivity. Thus, an extensive log analysis is a major step in the characterization methodology. When available, core samples and flow tests must also be reconsidered to enhance the model quality. Furthermore, petrophysical interpretation of logs will improve site characterization and enable mineral trapping assessment. The consistent re-interpretation of available well logs will ensure proper site characterization in terms of reservoir and containment. Some examples are provided to illustrate the relevance of re-interpretation work. Building a 3-D geological model is a major integrating step of the available dataset on the area of interest both in terms of structure and heterogeneities at different scales (facies, mineral, petrophysical…). At this stage, the different assumptions should be carefully revisited in light of the available data. The geological uncertainties can then be estimated using a statistical approach, which highlights key petrophysical characteristics of the storage along with main risks that need to be assessed. The final step in the characterization methodology includes a dynamic assessment of the short term effects on injectivity and capacity, and of long term trapping mechanism. On the short term, potential interference with other sub-surface activities needs to be investigated along with the potential migration pathways (existing wells and faults). Models were elaborated at different scales. A near-wellbore model helped to estimate chemical induced effects. A storage site model helped to estimate overpressure and CO 2 plume behaviors, and a model larger than the storage complex helped to identify migration pathways and constraint boundary conditions. Different assumptions and operational constraints were supposed to ensure the robustness of different injection scenarios. The results of corresponding dynamic simulations are presented and discussed.