Displays

This work is part of the Aquifer CO₂-Leak project, started in 2018 for a 4-years duration and that aims at evaluating the impact of CO₂ leakages from a geological storage site and developing new monitoring tools and methodologies. The present study aims to understand, quantify and model the environmental impact of a CO₂ leak on water quality in the carbonate freshwater aquifer and understanding CO₂-water-carbonate interactions.

This research has been performed on an experimental site located in Saint-Emilion (Gironde, France), in an underground quarry within a 30-meter-thick carbonate formation dated to the Upper Oligocene. The facies vary from wackestone to grainstone, and are associated with high values of porosity (from 25 to 45%) and permeability (between 5 and 20 D). A gas mixture, composed of CO₂ (90%), He (9%) and Kr (1%), was injected in the aquifer through a borehole located upstream hydraulic gradient. The total injected volume was 200 liters for 1h30.

The seven other boreholes downstream in the injection well were fitted with in-situ probes which automatically measured pH, electrical conductivity, and CO₂ fraction. Periodic water samplings have been undertaken, to determine the elementary concentrations by ionic chromatography. The spread of dissolved CO₂ in the freshwater aquifer has influenced the physicochemical parameters at the various measurement points and thus has been followed in the time.

The interaction between the CO₂ and the limestones causes the dissolution of the calcite, releasing Ca²⁺ and CO₃^2- in the solution, which are distributed between H₂CO₃, HCO₃^- and CO₃^2-. The comparison of the results before and after the passage of the plume highlights a dissolved CO₂ concentration increase, combined with an increase of electrical conductivity and temperature, as well as a decrease in pH values.

The evolution of the physicogeochemical signature in the aquifer allow to understand the reactive and transport processes during a migration of a CO₂ plume in a leakage context. The acquisition of these results will make possible to model a leakage in a complex natural reservoir.  Electrical conductivity and pH measurements seem to be excellent indicators for monitoring a gas plume during CO₂ geological storage. The laboratory analyzes lead to better understand the CO₂-water-carbonate interactions produced at the field scale and the relationships with petrophysical properties.

Batch measurements study the evolution of the electrical conductivity, monitored as a function of the CO₂ concentrations. Comparison of experiments using only water, water and sand or water and limestone, have shown that only the presence of carbonate ions allows an increase in this geophysical parameter.

By means of these different tools and measures, the propagation of a CO₂ leak will be followed through the modification of physicochemical parameters in the aquifer. This should also change the electrical resistivity values across the unsaturated zone. The electrical resistivity tomography should be a complementary tool in order to support these results, and to represent a 3D image plus time of the CO₂ plume.

How to cite: Petit, A., Cerepi, A., Loisy, C., Le Roux, O., Rossi, L., Chiquet, P., Estublier, A., Gance, J., Garcia, B., Gauchet, L., Hautefeuille, B., Lavielle, B., Luu Van Lang, L., Noirez, S., Texier, B., Bachaud, P., and Bouquet, S.: Aquifer-CO2 Leak project: Physicochemical characterization of the CO2 leakage impact on a carbonate shallow freshwater aquifer, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-13889, https://doi.org/10.5194/egusphere-egu2020-13889, 2020.

Power plants emit large amounts of carbon dioxide into the atmosphere primarily through the combustion of fossil fuels, leading to accumulation of increased greenhouse gases in the earth’s atmosphere. Global climate changing has led to increasing global mean temperatures, particularly over the poles, which threatens to melt gas hydrate reservoirs, releasing previously trapped methane and exacerbating the situation.  Here we used gas hydrate-based technologies to develop techniques for capturing and storing CO₂ present in power plant flue gas as stable hydrates, where CO₂ replaces methane within the hydrate structure. First, we experimentally measured the thermodynamic properties of various flue gases, followed by modelling and tuning the equations of state. Second, we undertook proof of concept investigations of the injection of CO2 flue gas into methane gas hydrate reservoirs as an option for economically sustainable production of natural gas as well as carbon capture and storage. The optimum injection conditions were found and reaction kinetics was investigated experimentally under realistic conditions. Third, the kinetics of flue gas hydrate formation for both the geological storage of CO₂ and the secondary sealing of CH₄/CO₂ release in one simple process was investigated, followed by a comprehensive investigation of hydrate formation kinetics using a highly accurate in house developed experimental apparatus, which included an assessment of the gas leakage risks associated with above processes.  Finally, the impact of the proposed methods on permeability and mechanical strength of the geological formations was investigated.

How to cite: Hassanpouryouzband, A., Edlmann, K., Yang, J., Tohidi, B., and Chuvilin, E.: CO2 Capture and Storage from Flue Gas Using Novel Gas Hydrate-Based Technologies and Their Associated Impacts, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-20863, https://doi.org/10.5194/egusphere-egu2020-20863, 2020.

CO₂ storage operators are required to monitor storage safety during injection with a long-term perspective (Ringrose and Meckel, 2019), implying that efficient measurement, monitoring and verification (MMV) plans are of critical importance for the viability of such projects. MMV plans usually include containment, conformance and contingency monitoring. Conformance monitoring is carried out to verify that observations from monitoring data are consistent with predictions from prior reservoir modelling within a given uncertainty range. Quantitative estimates of relevant reservoir parameters (e.g. pore pressure and fluid saturations) are usually derived from geophysical monitoring data (e.g. seismic, electromagnetic and/or gravity data) and potential prior knowledge of the storage reservoir.

In this work, we describe and apply a two-step strategy combining geophysical and rock physics inversions for quantitative CO₂ monitoring. Bayesian formulations are used to propagate and account for uncertainties in both steps (Dupuy et al., 2017). We apply our workflow to data from the Sleipner CO₂ storage project, located offshore Norway. At Sleipner, the CO₂ has been injected at approx. 1000 m deep, in the high porosity, high permeability Utsira aquifer sandstone since 1996 with an approximate rate of 1 million tonnes per year. We combine seismic full waveform inversion and rock physics inversion to show that 2D spatial distribution of CO₂ saturation can be obtained. Appropriate and calibrated rock physics models need to take into account the way fluid phases are mixed together (uniform to patchy mixing) and the trade-off effects between pore pressure and fluid saturation. For the Sleipner case, we show that the pore pressure build-up can be neglected and that the derived CO₂ saturation distributions mainly depend on P-wave velocities and on the rock physics model. The CO₂ saturation is larger at the top of the reservoir and the mixing tends to be more uniform. These mixing properties are, however, one of the main uncertainties in the inversion. We discuss the added value of a joint rock physics inversion approach, where multi-physics (electromagnetic, seismic, gravimetry), and multi-parameter inversion can be used to reduce the under-determination of the inverse problem and to better discriminate pressure, saturation, and fluid mixing effects.

Acknowledgements:

This publication has been produced with support from the NCCS Centre, performed under the Norwegian research program Centres for Environment-friendly Energy Research (FME). The authors acknowledge the following partners for their contributions: Aker Solutions, Ansaldo Energia, CoorsTek Membrane Sciences, Emgs, Equinor, Gassco, Krohne, Larvik Shipping, Lundin, Norcem, Norwegian Oil and Gas, Quad Geometrics, Total, Vår Energi, and the Research Council of Norway (257579/E20).

References:

Dupuy, B., Romdhane, A., Eliasson, P., Querendez, E., Yan, H., Torres, V. A., and Ghaderi, A. (2017). Quantitative seismic characterization of CO₂ at the Sleipner storage site, North Sea. Interpretation, 5(4):SS23–SS42.

Ringrose, P. S. and Meckel, T. A. (2019). Maturing global CO₂ storage resources on offshore continental margins to achieve 2DS emissions reductions. Scientific Reports, 9(1):1–10.

How to cite: Dupuy, B., Romdhane, A., and Eliasson, P.: Quantitative CO2 monitoring workflow, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-8912, https://doi.org/10.5194/egusphere-egu2020-8912, 2020.

CO₂ geological storage (CGS) proved to be an enormously significant mid-to-long-term solution for mitigating and even nullifying the net greenhouse gas emissions, and CO₂-enhanced water recovery (CO₂-EWR) technology may improve the efficiency of CO₂ injection and saline water production with potential economic value as a means of storing CO₂ and supplying cooling water to power plants. The strata with dip-angle are common in nature, because of the effects of geological structure and diagenesis. It is of great significance to study the influence of the dip-angle on the efficiency and safety of CO₂-EWR. Based upon the typical formation parameters of the China Geological Survey CO₂-EWR test site in the eastern Junggar Basin, a series of three-dimensional (3D) injection-extraction models with fully coupled wellbores and reservoirs were established to evaluate the effect of dip-angle on the enhanced efficiency of CO₂ storage and saline production, considering geochemical reactions. Numerical simulation results show that the dip-angle has a regular influence on the formation pressure field, the CO₂ transport distance in the reservoir and the CO₂ sealing capacity, and the influence of dip-angle strata on the total storage amount of CO₂ changed in a non-monotone mode compared with the CO₂ geological storage in horizontal strata at the same injection condition. The effect of water chemical characteristics on the migration of CO₂ in different phases and the transformations of major sequestered carbon minerals were determined from the resulting mechanism. Because non-horizontal strata are predominant in deep saline aquifers in nature, regardless of the influence of formation dip, CO₂ leakage risks in geological storage will be greatly underestimated, and the stratum dip angle must be considered in research related to CO₂ geological storage. Overall, the results of analysis provide a guide and reference for the CO₂-EWR site selection.

How to cite: Yang, Z., Dai, Z., Xu, T., Wang, F., and Jia, S.: Effects of Dip-angle on the CO2-Enhanced Water Recovery Efficiency and Reservoir Pressure Control Strategies, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-13028, https://doi.org/10.5194/egusphere-egu2020-13028, 2020.

In accordance with the European Union target of 80-95% reduction in net greenhouse gas emissions for the year 2050 relative to 1990 levels, as well as the 2050 German directive for Net-Zero greenhouse gas emissions, the Helmholtz Inititive for Climate Adaptation and Mitigation aims to provide the innovation and decision-making guidance required to both minimize future emissions and improve societal resilience to the negative consequences of anthropogenic climate change.

While the rapid development of clean energy generation infrastructure, associated with cross-sector energy efficiency improvements and progress of low-carbon technologies such as electric vehicles represent tangible contributions to this goal, a large degree of emissions remain tied to industrial processes at the core of German economic output, notably within refineries, the iron and steel industry and the cement and lime industry.

In parallel to searching for low-carbon process alternatives, or utilisation scenarios for tough-to-decarbonise emissions, the case for underground CO2 storage remains attractive both economically and from a safety point of view [1].

The German onshore territory presents a large potential for carbon storage owing to a number of stratigraphic layers presenting favourable storage characteristics (depth, thickness, porosity, as well as surrounding rock properties) with considerable geographical extent.

A significant aspect in establishing cost-effective carbon networks that are engaging for both the public and industrial partners is the creation of advantageous organisational structures that take into account viable placement of storage sites, minimal-cost pipeline networks, coherent regional grouping, sensitivity to public concerns, as well as awareness of future emission landscapes.

As a consequence, we propose a national-scale study in which we address the aforementioned constraints to create hypothetical CO2 networks based on varying regional clustering methods, number of storage sites, pipeline scalability costs and underground storage and transport constraints relating to public acceptance.

We make use of recently published graph-optimisation algorithms to ensure we achieve close-to-optimal network structures for each input CO2 sources and storage sites, and usable land space for transport [2].

The geological data used is based on literature work establishing potential CO2 storage sites, as well as a catalogue of faults of which the fault-zone conductivity is not necessarily known [3]. CO2 emission data is taken from the EU carbon trading emitters register and future emission scenarios exclude fossil energy generation.

Our results show that a large diversity of CO2 networks can be envisioned for a 2050 German Net-Zero landscape while still maintaining acceptable regional exclusivity, owing primarily to the large degree of underground storage potential available. One aspect that is not considered is the prospect of trans-national CO2 networks that could benefit both locally certain large isolated point sources close to country borders or more globally through infrastructure economy of scale.

[1] Global Status of CCS: 2019, Global CCS Institute

[2] Heijnen, P., Chappin, E., Herder, P. (2019): A method for designing minimum‐cost multisource multisink network layouts. - Systems Engineering, Volume 23, Issue 1, Pages 14-35

[3] Schulz, R., Suchi, E., Öhlschläger, D., Dittmann, J., Knopf, S. & Müller, C. (2013): Geothermie-Atlas zur Darstellung möglicher Nutzungskonkurrenzen zwischen CCS und Tiefer Geothermie. – Endbericht, LIAG-Bericht

How to cite: Yeates, C., Schmidt-Hattenberger, C., and Bruhn, D.: Potential CO2 Networks for Carbon Storage in a German Net-Zero Emission Landscape, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-20085, https://doi.org/10.5194/egusphere-egu2020-20085, 2020.

Understanding potential caprock failure through fault zone leakage is crucial for the safe, long-term containment of a CO₂ storage site. Thus, the presence of faults in caprocks will greatly affect the site characterization process in terms of the safety assessment. The CS-D experiment at the Mont Terri Lab aims at investigating caprock integrity by determining CO₂-rich water mobility in a fault zone. Seven boreholes were drilled in the clay rock, all crosscutting a fault at depths of 17-30 m below the niche floor. The boreholes were fully cored, and the samples analysed in various laboratories. All boreholes were instrumented for monitoring geochemical and geomechanical changes induced by fluid injection for prolonged time, with the goal to better understand mechanisms of CO₂ leakage in a faulted caprock. We deployed a multi component monitoring setup measuring pressure, axial and 3D deformation, seismic activity and cross-hole electrical resistivity. A borehole was fully dedicated to the monitoring of the injection front, as well as geochemical in-situ measurements and fluid sampling. A portable mass spectrometer for direct measurements of gas has been installed in a dedicated borehole interval. Injection and monitoring activities started in December 2018, with multiple injection tests with saline water at pressures up to 6 MPa, in order to characterize the hydraulic response of the fault. A prolonged injection of CO₂-saturated water at constant head pressure started in June 2019 and lasted for about 8 months. In this contribution, we will present the analysis of the data collected during the fault characterization (hydraulic, geophysics, and core analysis) as well as results of the continuous months-long injection. Preliminary interpretation of the monitoring data suggests that a fault does not necessarily form a pathway for the fluid to escape at shallow depth.

How to cite: Wenning, Q. C., Rinaldi, A. P., Zappone, A., Grab, M., Roques, C., Webber, U. W., Jaggi, M., Bernasconi, S. M., Guglielmi, Y., Brennwald, M., Kipfer, R., Madonna, C., Obermann, A., Nussbaum, C., and Wiemer, S.: Fault hydromechanical characterization and CO2-saturated water injection at the CS-D experiment (Mont Terri Rock Laboratory), EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-19243, https://doi.org/10.5194/egusphere-egu2020-19243, 2020.

Natural gas (methane) has rapidly become a critically important component to the energy economies of the United States and other countries. Because storage capacity in the above-ground pipeline network is insufficient to meet demand, natural gas is stored in large underground (UGS) facilities both in the US and, to an increasing extent, throughout the world. Defining a baseline for the frequency of reported and documented off-normal occurrences, including human error, process safety, mechanical or operational issues, or natural events with or without leakage, at UGS facilities is critical to maintaining safe operation and to the development of appropriate risk management plans and regulatory approaches.

We have analyzed the frequency of off-normal occurrences at US UGS facilities hosted by each US state. Some 31 states host UGS facilities in porous rock (depleted oil-and-gas field and aquifer), and/or solution-mined salt cavern storage facilities. Data are based upon extensive searches of information available in the public domain and not all occurrences involve the stored gas or its release but which, in combination with other factors, could lead to significant problems. The number of reported occurrences, normalized by the number of facilities and the years of active operation, define the mean occurrence frequency per facility-year for each state. Bayesian probabilistic analysis then characterizes the historical occurrence frequencies and uncertainties, parsed by storage facility type, above-ground or below-ground causes, and severity of occurrence.

Both UGS facility-years and nuisance-level occurrences for depleted field storages are highly variable from state to state, for both above-ground and below-ground causes. Aquifer storage facilities show large numbers of occurrences relative to the number of facility-years, with above-ground occurrences identified for four states and a smaller number of below-ground occurrences found for a larger number of states. Salt-cavern storage has a large number of occurrences over a relatively small number of facility-years: most of which are associated with below-ground causes.

Nuisance-level occurrence frequencies for porous-rock storage facilities and for both above-ground and below-ground causes, are generally in the range of 10^–1 to 10^–3 occurrences per facility-year except for those in California, which exceed 10^–1 occurrences per facility-year. Serious or catastrophic occurrence frequencies for depleted field storage facilities decrease to less than about 10^–2 occurrences per facility-year for most states. Nuisance-level occurrence frequencies for salt-cavern storage facilities exceed 10^–2 occurrences per facility-year for below-ground causes, whilst serious or catastrophic occurrences decrease to about 10^–3 to 10^–1 occurrences per facility-year.

How to cite: Schultz, R. and Evans, D.: State-by-state comparison of off-normal occurrence frequencies for US underground natural gas storage facilities, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-1387, https://doi.org/10.5194/egusphere-egu2020-1387, 2020.

To meet global commitments to reach net-zero carbon emissions by 2050, the energy mix must reduce emissions from fossil fuels and transition to low carbon energy sources.  Hydrogen can support this transition by replacing natural gas for heat and power generation, decarbonising transport, and facilitating increased renewable energy by acting as an energy store to balance supply and demand. For the deployment at scale of green hydrogen (produced from renewables) and blue hydrogen (produced from steam reformation of methane) storage at different scales will be required, depending on the supply and demand scenarios. Production of blue hydrogen generates CO₂ as a by-product and requires carbon capture and storage (CCS) for carbon emission mitigation.  Near-future blue hydrogen production projects, such as the Acorn project located in Scotland, could require hydrogen storage alongside large-scale CO₂ storage. Green hydrogen storage projects, such as renewable energy storage in rural areas e.g. Orkney in Scotland, will require smaller and more flexible low investment hydrogen storage sites. Our research shows that the required capacity can exist as engineered geological storage reservoirs onshore and offshore UK. We will give an overview of the hydrogen capacity required for the energy transition and assess the associated scales of storage required, where geological storage in porous media will compete with salt cavern storage as well as surface storage such as line packing or tanks.

We will discuss the key aspects and results of subsurface hydrogen storage in porous rocks including the potential reactivity of the brine / hydrogen / rock system along with the efficiency of multiple cycles of hydrogen injection and withdrawal through cushion gasses in porous rocks. We will also discuss societal views on hydrogen storage, exploring how geological hydrogen storage is positioned within the wider context of how hydrogen is produced, and what the place of hydrogen is in a low-carbon society. Based on what some of the key opinion-shapers are saying already, the key considerations for public and stakeholder opinion are less likely to be around risk perception and safety of hydrogen, but focussed on questions like ‘who benefits?’ ‘why do we need hydrogen in a low-carbon society?’ and ‘how can we do this in the public interest and not for the profits of private companies?’

We conclude that underground hydrogen storage in porous rocks can be an essential contributor to the low carbon energy transition.

How to cite: Edlmann, K., Heinemann, N., Mabon, L., Mouli-Castillo, J., Hassanpouryouzband, A., Butler, I., Thaysen, E., Wilkinson, M., and Haszeldine, S.: Seasonal storage of hydrogen in porous formations, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-10475, https://doi.org/10.5194/egusphere-egu2020-10475, 2020.

Storing dihydrogen (H₂) underground in salt caverns is seen as a vector of the energy transition. To ensure that risks related to leakage are managed, monitoring methods are needed to detect any H₂ unintended migration. Because the shallow subsurface will act as an ultimate barrier before the gas reaches surface and dwellings, there is also a need to increase knowledge on geochemical impacts of a H₂ leakage on shallow environments.

Geochemical monitoring methods exist and make it possible to detect H₂ directly (H₂ concentrations in dissolved and gaseous phases) or indirectly (e.g. CO₂, O₂, N₂ concentrations in dissolved and gaseous phases, ionic balance and some trace elements, redox potential).

Within the framework of the Rostock'H project funded by the French R&D program GEODENERGIES, a leakage in the shallow subsurface was simulated by injecting water with dissolved H₂ into the aquifer (~20 m deep). Injection was done in November 2019 on a dedicated experimental site and aimed at testing monitoring techniques but also at studying geochemical impacts at very shallow depths. The site is located in the Paris sedimentary basin (Catenoy city). The unconfined aquifer is within the Senonian (Cretaceous) chalk formation. The overlying unsaturated zone includes Bracheux sands (Paleogene) and Quaternary colluvium. The average water table is 12 m deep. The underground water has calcium-bicarbonate facies and a pH close to neutral. Eight piezometers were drilled, aligned over 80 m in the direction of the aquifer main flow (West-East) and slotted between 12 and 25 m deep. Moreover, four dry boreholes were drilled above the piezometric level to monitor the unsaturated zone. Each one was in the close vicinity of a piezometer and slotted between 3 and 11 m deep. The site was equipped with geochemical monitoring tools selected or developed by Ineris and University of Lorraine. For instance, one of the monitoring wells was equipped with a gas completion and connected to a gas RAMAN probe and to a MID IR gas cell with low optical path.

For the experiment purpose, 5 m³ of underground water were pumped, saturated with H₂ at surface conditions and injected again in the aquifer using one of the piezometers. The H₂ injection was preceded by an injection of 1 m³ of underground water saturated with selected chemically inert gas tracer (helium: He) and containing two selected hydrological tracers (uranine and lithium chloride) to anticipate the H₂ arrival in the downstream piezometers used as monitoring wells. Dissolved gas concentrations (He, H₂, N₂, O₂, CO₂, H₂S and CH₄) were very frequently monitored in situ in the first 4 downstream piezometers (until 20 m from the input well) during the first week. Consequently, the maximum concentrations of dissolved He and H₂ were respectively detected 49 hours and 71 hours after the injection started in the piezometer located 10 m downstream the injection well. Moreover, water samples were collected at several time steps to analyze, in laboratory, ionic balance and trace element concentrations in order to assess the environmental impact of a H₂ leakage.

How to cite: Lacroix, E., Lafortune, S., De Donato, P., Gombert, P., Pokryszka, Z., Adélise, F., Caumon, M.-C., Barrès, O., and Rupasinghe, S.: Development of monitoring tools in soil and aquifer for underground H2 storages and assessment of environmental impacts through an in-situ leakage simulation, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-17949, https://doi.org/10.5194/egusphere-egu2020-17949, 2020.

Energy transition involves an increasing demand for renewable energies. Room heating and hot water account for the majority of the energy demand of private households. Thus, seasonal storage of excess heat produced during the summertime and extracted during the wintertime is of paramount importance. High temperature heat storage in the subsurface may be realized in abandoned hydrocarbon reservoirs worldwide as these reservoirs have already been extensively characterized concerning their geology, geo- and petrophysical properties as well as their depths and geometries. Although these hydrocarbon reservoirs are relatively well characterized, their potential use for geothermal heat storage has not yet been investigated. Here we focus in a first approach on abandoned oilfields of the Upper Rhine Graben (URG) in SW Germany with the aim to assess their potentials for geothermal heat storage. While geothermal production commonly targets fractured reservoirs to obtain economically viable flowrates, geothermal heat storage will aim at reservoirs with high porosities. As the productivity of hydrocarbon reservoirs is commonly controlled by their porosities, they appear as viable targets for high temperature heat storage.

We have characterized 20 abandoned hydrocarbon reservoirs in the URG, which were productive for more than five years, in Cenozoic sandstones in depths of approximately 200 – 1800 m. Our characterization is based on published data of their production histories, reservoir geology, and petrophysical properties. Most reservoirs in the URG are stacked reservoirs with inflow of hydrocarbons into the borehole from multiple stratigraphic units, as for example in Landau and Leopoldshafen, biasing an assignment of respective reservoir productivity. For heat storage injection pressure needs to be well controlled to avoid undesired hydraulic fracturing. Therefore, (theoretically) infinite reservoirs with high transmissivities appear to be more attractive and less risky than confined reservoirs.

The production histories of the various hydrocarbon reservoirs show typical patterns with a rapid increase of the annual production, followed by a slower decrease of production (tailing) before hydrocarbon production was shut down. Most reservoirs in Cenozoic sandstones show porosities of 10 to 20% with some extreme values of up to 30%. Associated permeabilities vary from 0.1 to 100 mD with some extreme values of up to 1000 mD. Data show a non-linear relationship between porosity and permeability. During hydrocarbon production water-oil ratios increase until unalluring water-oil were produced. We evaluate the potential of abandoned hydrocarbon reservoirs in the URG for heat storage by developing generic numerical models to constrain limiting conditions. The uncertainties of input parameters and their impact on heat storage potential will be addressed by a sensitivity analysis. Potential reservoirs for heat storage may be defined based on energy recovered over invested energy (EROI). Preliminary results of our numerical models show a strong dependency of the storage potential on increasing flowrates as well as on decreasing thermal conductivities of the reservoir and especially the confining layers below and above.

How to cite: Stricker, K., Grimmer, J., Meixner, J., Dashti, A., Egert, R., Gholamikorzani, M., Schaetzler, K., Schill, E., and Kohl, T.: Utilization of abandoned hydrocarbon reservoirs for deep geothermal heat storage, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-20723, https://doi.org/10.5194/egusphere-egu2020-20723, 2020.

Seasonal storage of excess heat in hot deep aquifers is one of the considered solutions to optimize the usage of commonly available energy sources. This study investigates the risk of damaging the reservoir through potential geochemical reactions induced by the increased reservoir temperature upon injection of heated formation water. Three core flooding experiments were performed at reservoir conditions and temperatures up to 150°C with cores from two potential Danish geothermal reservoirs and with synthetic brine as the flooding fluid. The tested reservoir sandstones comprise two samples with different mineralogy from the Upper Triassic – Lower Jurassic Gassum Sandstone Formation and one sample from the Lower Triassic Bunter Sandstone Formation. For the calcium carbonate-containing Bunter Sandstone formation, the experiments were performed with Ca-depleted synthetic formation water to avoid loss of injectivity by calcium carbonate scaling at elevated temperatures. The interpretation of the laboratory experiments was supported by petrographic analysis of the cores prior to and after the flooding experiments and by geochemical modelling. The results show that heating induced a series of silica dissolution/precipitation processes for all three sandstones, including dissolution of quartz, alteration of Na-rich feldspar to kaolinite, replacement of plagioclase with albite and precipitation of muscovite, depending on the sandstone. These processes are not expected to significantly deteriorate the physical properties of the reservoir. However, for the Bunter Sandstone Formation, flushed with Ca-depleted brine, a significant portion of the cementing calcite dissolved. In the reservoir, this may ultimately reduce the mechanical strength of the geological formation. Thus, this study suggests that heat storage in geothermal reservoirs can be technically feasible in typical and extensive Danish geothermal sandstone reservoirs. However, in reservoirs containing calcium carbonate, means for avoiding calcium carbonate precipitation during heat storage should be chosen with caution to minimise possible reservoir damaging side effects.

How to cite: Holmslykke, H. D., Kjøller, C., Weibel, R., and Fabricius, I. L.: Laboratory and modelling investigations of potential geochemical reactions upon seasonal heat storage in Danish geothermal reservoirs, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-13678, https://doi.org/10.5194/egusphere-egu2020-13678, 2020.

In regions with long cold overcast winters and sunny summers, Deep Direct-Use (DDU) can be coupled with Reservoir Thermal Energy Storage (RTES) technology to take advantage of pre-existing subsurface permeability and storage capacity to save summer heat for later use during cold seasons. Many aquifers worldwide are underlain by permeable regions (reservoirs) containing brackish or saline groundwater that has limited beneficial use due to poor water quality. We investigate the utility of these relatively deep, slow flowing reservoirs for RTES by conducting an integrated feasibility study in the Portland Basin, Oregon, USA, developing methods and obtaining results that can be widely applied to groundwater systems elsewhere. As a case study, we have conducted an economic and social cost-benefit analysis for the Oregon Health and Science University (OHSU), a teaching hospital that is recognized as critical infrastructure in the Portland Metropolitan Area. Our investigation covers key factors that influence feasibility including 1) the geologic framework, 2) hydrogeologic and thermal conditions, 3) capital and maintenance costs, 4) the regulatory framework, and 5) operational risks. By pairing a model of building seasonal heat demand with an integrated model of RTES resource supply, we determine that the most important factors that influence RTES efficacy in the study area are operational schedule, well spacing, the amount of summer heat stored (in our model, a function of solar array size), and longevity of the system. Generally, heat recovery efficiency increases as the reservoir and surrounding rocks warm, making RTES more economical with time. Selecting a base-case scenario, we estimate a levelized cost of heat (LCOH) to compare with other sources of heating available to OHSU and find that it is comparable to unsubsidized solar and nuclear, but more expensive than natural gas. Additional benefits of RTES include energy resiliency in the event that conventional energy supplies are disrupted (e.g., natural disaster) and a reduction in fossil fuel consumption, resulting in a smaller carbon footprint. Key risks include reservoir heterogeneity and a possible reduction in permeability through time due to scaling (mineral precipitation). Lastly, a map of thermal energy storage capacity for the Portland Basin yields a total of 87,000 GWh, suggesting tremendous potential for RTES in the Portland Metropolitan Area.

How to cite: Bershaw, J., Burns, E. R., Cladouhos, T. T., Horst, A. E., Van Houten, B., Hulseman, P., Kane, A., Liu, J. H., Perkins, R. B., Scanlon, D. P., Streig, A. R., Svadlenak, E. E., Uddenberg, M. W., Wells, R. E., and Williams, C. F.: An Integrated Feasibility Study of Reservoir Thermal Energy Storage in Portland, OR, USA, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-11383, https://doi.org/10.5194/egusphere-egu2020-11383, 2020.

Salt caverns are created during the process of solution mining or built actively for underground storage purposes required for the energy transition. In most cavern-scale numerical models, deviatoric stresses within the salt dome are assumed to be negligible in magnitude. However, as salt structures are typically not homogeneous, this assumption is known to be incorrect. Stress variations may be caused by internal heterogeneities such as the presence of anhydrite layers, or by the large-scale structure and ongoing deformation of the salt dome or pillow as a result of their lower density compared to the overlying rocks. The rheology of the salt itself, a not very well constrained parameter, which varies significantly between different types of salt, may also have a significant effect.

In the scope of the Dutch KEM-17 project (Knowledge Programme on Effects of Mining) on Over-pressured salt solution mining caverns and possible leakage mechanisms, we examined which differential stresses can develop in a typical salt-structure (salt pillow, salt wall, and flat-bedded salt).  In order to make recommendations for avoiding undesired interference effects between caverns and salt dome boundaries, it is crucial to understand better how the stresses caused by salt-deformation vary within the salt dome. Which lower/upper bounds are to be expected for a particular type of structure? Where are such stresses likely to be negligible, and can we safely use existing approaches that neglect the background stress field? To what extent do uncertainties in the model parameters and geometries affect the stress state in the salt dome? To answer these questions, we used 3D thermomechanical models, for which we incorporated the state-of-the-art rheological flow laws of salt and assessed the stress state over approximately 300 kyrs, including the effect of tectonic regimes and glacial (un-)loading.

How to cite: Baumann, T., Kaus, B., Popov, A., and Urai, J.: The 3D stress state within typical salt structures, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-15513, https://doi.org/10.5194/egusphere-egu2020-15513, 2020.

Underground pumped storage hydropower (UPSH) is an alternative energy storage system (ESS) for flat regions, where conventional pumped storage hydropower plants cannot be constructed due to topographical limitations. UPSH plants consist in two reservoirs, the upper one is located at the surface or possibly underground (but at shallow depth) while the lower one is underground. Although the underground reservoir can be drilled, the use of abandoned mines (deep or open pit mines) as underground reservoir is a more efficient alternative that is also beneficial for local communities after the cessation of mining activities. Given that mines are rarely waterproofed, water exchanges between UPSH plants and the underground medium are expected. Water exchanges may have negative consequences for the environment, but also for the feasibility of UPSH plants. The impacts on the environment and the plant efficiency may have hydraulic (changes of the natural piezometric head distribution, effects in the hydraulic head difference between the two reservoirs, etc.) or hydrochemical nature (dissolution and/or precipitation of minerals in the aquifer and in the reservoirs, corrosion of facilities, modification of pH, etc.). At this stage, it is required a sound understanding of all the impacts produced by the water exchanges and evaluate under which circumstances they are mitigated. This assessment will allow ascertaining criteria for the selection of the best places to construct future UPSH plants.

How to cite: Pujades, E.: An overview about the interaction between the underground pumped storage hydropower (UPSH) and the saturated subsurface medium: effects of the water exchanges on the environment and the plant efficiency , EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-5531, https://doi.org/10.5194/egusphere-egu2020-5531, 2020.

The long-term managing from the geological hazard point of view of the Hontomín onshore pilot-plant for CO₂ storage, located in Spain and recognized as the first and only key-test facility in Europe, is one of the main objectives stated in the ENOS European project. This project is led and funded by the European Network of Excellence on the Geological Storage of CO₂ (CO₂GeoNet).

The complex geological emplacement of the Hontomín Carbon capture and storage plant is considered rather relevant to analyse the impact of fracturing and both local and regional strain field on the reservoir parameters. The reservoir of Hontomín pilot-plant is formed by highly fractured Middle Jurassic dolomites with associated secondary porosity. This parameter is one of the main concerns when managing CO₂ storage and monitoring.

In order to characterize the fracture pattern and its implications on a proper CO₂ monitoring, we characterized the surface structural elements through the study area and their relationship with fractures affecting the reservoir porosity. The methodology followed in this work is mainly based on detailed geological mapping (field work complimented with orthophoto analysis), adding missing information from previous works. This analysis does not increase the cost for long-term monitoring, given that they are low-cost and the results are acquired in a few months.

The main structural trend in the study area, concerning faults with a wide range of displacement and metric to decametric folds, follows a regional E-W orientation. On the other hand, fractures show two main sets of trends, from NW-SE to NE-SW.

This fracturing pattern, considered as a conjugate fracture system, corresponds to the tectonic stress recorded in both Mesozoic and Cenozoic sedimentary successions where the Hontomín pilot-plant is placed. Riddle faults formed from a nearby regional right-lateral strike slip fault (Ubierna Fault) are the responsible structures for the fracture system affecting the area and the reservoir. Moreover, this fracturing pattern is in agreement with local to regional active tectonic field from Cenozoic times to present-day, when the Ubierna Fault recorded its maximum right-lateral displacement (15 km).

Secondary porosity within the reservoir can be produced from this fracture pattern, highly increasing the permeable migration paths for CO₂ migration after the injection. Therefore, we state that a combination between fracture analysis and structural and tectonic study, should be considered as mandatory in the monitoring phases of the CO₂ plume, during and after injection operations.

How to cite: Ramos, A., Mediato, J. F., Pérez-López, R., Rodríguez-Pascua, M. A., Martínez-Orío, R., and Fernández-Canteli, P.: Role of fracturing and regional tectonic structures on secondary porosity generation in a CO2 storage plant: Hontomin pilot-plant (Spain), EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-440, https://doi.org/10.5194/egusphere-egu2020-440, 2020.

The EU H2020 GECO (Geothermal Emission Gas Control) project is aimed to produce new technologies to limit emissions from geothermal power generation by either gas re-injection or its use to produce commercial material through serpentinite carbonation. In this framework, the realization of a closed loop geothermal power plant has been planned in the Lardello geothermal area (Italy), where gas will be re-injected in a reservoir constituted by phyllites and micaschists.

A set of water-gas-rock interaction experiments was performed in order to: i) investigate the interaction between CO₂-H₂S gas mixture, representative of the geothermal fluids exploited at Larderello, and phyllites and micaschists of the reservoir ii) optimize the conditions for CO₂ mineral sequestration by reacting CO₂-H₂S gas mixture with different serpentinised ultramafic rocks buried in the nearby area. During the experiments, rock powder suspended in ultrapure ion-free MilliQ® water were reacted with a gas phase (CO₂-H₂S=98-2% or CO₂=100%) in a PARR 5500 HP stirred reactor at P-T conditions ranging from 20 to 60 bar and 90 to 250 °C, respectively. The liquid phase resulting from the experiments was analysed via ion chromatography and ICP-MS to determine ion contents, whilst rock and rock powder were examined with SEM-EDS and EPMA to identify mineral phases and determine mineral chemistry.

Preliminary results highlighted that H₂S plays a pivotal role in controlling the reaction pathways with phyllites and micaschists, allowing the formation of pyrite in a wide range of P-T conditions. This process induces a selective removal of Fe from the solution, while the exceeding SiO₂ deriving from mica and chlorite alteration re-precipitate as quartz. In this experiment, carbonate precipitation is prevented by the low Ca and Mg content of the samples and by the high water to rock ratio constrained by the experimental set-up. Experiments with ultramafic rocks were performed using serpentinised harzburgite and brucite-rich dunite in order to identify the most reactive lithology for mineral carbonation. Preliminary results show that CO₂ sequestration is strongly enhanced by the presence of brucite compared to serpentine but further experiments are required to establish the most efficient reaction conditions.

This research is supported by European Horizon 2020 “GECO” project (Grant n° 818169).

How to cite: Bicocchi, G., Orlando, A., Ruggieri, G., Borrini, D., Rielli, A., and Boschi, C.: Towards zero emission geothermal plants in the framework of the H2020 GECO project: Insights on gas re-injection in geothermal reservoir and serpentinite carbonation from batch reactor experiments, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-691, https://doi.org/10.5194/egusphere-egu2020-691, 2020.

This study presents a CT scanning and image analysis protocol to characterize wellbore cement degradation under geologic CO2 storage (GCS) conditions. The CT scanning and image analysis procedures described in the protocol are as follows: 1) CT scanning of the cement sample before exposure to CO2; 2) exposure of the cement sample to supercritical CO2 or CO2 saturated brine; 3) CT scanning of the cement sample after the exposure experiment; 4) application of 3D rigid registration to align all CT image frames, in order to eliminate pixel location variation between CT image frames due to sample drift; 5) acquisition of grayscale intensity difference images, which are obtained by subtraction of CT images after the CO2 exposure experiment from raw CT images before the CO2 exposure experiment; 6) application of noise filtering technique on grayscale intensity difference images to obtain images with good quality; 7) acquisition of 3D pore structure change of the cement sample after CO2 exposure experiment from grayscale intensity difference images, showing degradation of wellbore cement. To demonstrate the application of the protocol, an experiment of reaction between CO2 and wellbore cement under GCS conditions was conducted and the wellbore cement samples used in the experiment went through aforementioned CT scanning and image analysis procedures. CT image analysis results demonstrate a region with increased porosity in the exterior of the cement samples (Zone 1) and a region with decreased porosity next to Zone I due to CaCO3 precipitation (Zone 2). Next to Zone 2, a region with increased porosity due to Ca(OH)2 and C-S-H dissolution (Zone 3) was observed. In summary, this study proves feasibility to use 3-D CT scanning and CT image analysis techniques to investigate CO2-induced degradation of wellbore cement.

How to cite: Zhang, L., Wang, Y., Gan, M., Liu, S., and Li, X.: Investigation on wellbore cement degradation under geologic CO2 storage conditions by micro-CT scanning and 3D image reconstruction, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-1801, https://doi.org/10.5194/egusphere-egu2020-1801, 2020.

Increasing the amount of renewable energy in the UK reduces greenhouse gas emissions but will also lead to intermittency of supply, especially on a seasonal timescale. Over-producing energy when demand is low and under producing when demand is high requires large-scale storage to redress the balance.  Hydrogen stored over seasonal timescales in subsurface porous rocks can act as a giant battery for the UK and is a flexible energy vector that can be used for heat, transport and electricity generation.

No large scale assessment of the hydrogen storage capacity of an industrialised region has yet been undertaken. Here, we present a novel method for calculating the hydrogen storage capacity of gas fields and saline aquifers on the UK continental shelf using data previously used to assess carbon-dioxide storage potential.

How to cite: Scafidi, J., Wilkinson, M., Gilfillan, S., and Heinemann, N.: Hydrogen storage in porous rocks: the storage capacity of the UK continental shelf, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-2103, https://doi.org/10.5194/egusphere-egu2020-2103, 2020.

Gases encountered in different salt beds from evacuated and packer-sealed borehole sections in a potash mine were sampled and characterized for their chemical and isotopic composition so as to conclude on their origin and evolution in the salt rocks.

These gases were either generated autochthonally or originate from fluid influx from the surrounding rocks outside the salt formation. Fixation in the salt rocks can take place laminar on mineral grain boundaries, disrupter and fracture zones or trapped in inclusions inside or between mineral grains.

In situ flow tests with pure argon between several boreholes at distances ranging from decimeter to meter suggest that formation gas is stripped from the intermediate salt packet. This gas must have been trapped on grain boundaries along the pathways of the flowing argon.

The stripped formation gas comprises mainly CO₂ with traces of CH₄ and H₂. The CO₂ isotopic composition matches well with gases originating from a mantle source, whereas CH₄ is classified to be of thermogenic origin formed in a marine environment. Plausible explanations for the H₂ generation are the radiolysis of water, reaction of FeII with water or microbial processes.

We conclude that these trapped gases are of allochthonous origin migrating from the surrounding rocks into the salt formation where they were fixated mainly along fracture surfaces and fissures.

How to cite: Zimmer, M. and Strauch, B.: Origin and evolution of gas in salt beds of a potash mine, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-2584, https://doi.org/10.5194/egusphere-egu2020-2584, 2020.

In general, the characterization of the heterogeneity in a reservoir is considered to be important in the exploration and selection of CO2 storage formation, but it is not clear how the heterogeneity affects the evolution of the pore pressure. In particular, long-term changes in the pore pressure when most of the storage candidates are bounded by faults or bedrock, such as Korea, have been rarely examined. Many literature related to results of studies and international CCS standardization indicate that the heterogeneity of storage formation should be identified, but it is still unclear to what extent the precision or resolution of the investigation is required at the selection or design stage. The heterogeneity of sedimentary layers can be divided into two categories in terms of geographic statistics. At this time, the criteria of the classification is statistical stationarity. From a geological point of view, the statistical stationarity may be consistent with the sedimentary environment. In other words, it can be assumed that strata deposited at the same place, at similar times, and in similar circumstances have similar hydrogeological properties, despite of some detailed differences. In this case, the heterogeneity refers to “detailed differences” and the homogeneity refers to statistical parameters such as means or variances of physical properties and spatial auto-covariance. On the other hand, the nonstationary heterogeneity refers to a case where there is no statistical homogeneity, due to differences in geological structures such as faults and differences in strata such as sandstone and mudstone. In this study, the numerical sensitivity analysis was used to investigate the effect of each heterogeneity on the pressure buildup. The nonstationary heterogeneity applied in this study is a vertical structure that completely penetrates the storage formation. The results of ten models with the stationary heterogeneity showed almost similar pressure changes in the macroscale, although there were some pore pressure differences at the injection well between each of models. The pressure difference at the injection well between each model was dependent on the bulk permeability within a certain distance (200m in this study) near the injection wells, not on the average permeability of the whole system. In other words, when the injection well is installed at a point having a relatively high permeability, some additional increase in pressure due to the heterogeneity rarely occurs. However, lowering the permeability due to nonstationary heterogeneity can causes the global pressure rise in the storage formation, results were very similar to those of the case with closed boundary condition when the heterogeneity reduced the permeability to 10-4 times or less of the permeability in the storage formation.

How to cite: Kim, T.: Long-term Pressure Evolutions due to Geologic Heterogeneities during CO2 Injection, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-4404, https://doi.org/10.5194/egusphere-egu2020-4404, 2020.

Well integrity issue is a major concern not only in the Oil and Gas industry but in the geo-storage field. For CO₂ sequestration, in particular, poor quality cement jobs render wells to suffer from possible CO₂ and formation fluid migration issues. In some cases, this migration issue maybe caused by the micro-fracture or micro-channel created during the chemical shrinkage and bulk shrinkage processes. Using some expandable cement system to cope with this issue is a promising way to mitigate this issue. In this study, we are exploring the effect of a kind of micro-MgO based expanding material on some principal properties of CO₂ sequestration well cement.

In these experiments, a typical cement formulation including various additives was used. Our focus of this pilot study was to investigate the effect of expandable materials on some typical physical-mechanical properties of Portland cement with different concentrations such as 0%, 1.0%, 2.0%, 3% by weight of cement (BWOC). Meanwhile, the pure Class G Portland cement slurry was also investigated as the base experiment. By use of API standard (RP 10B) procedures, those physical-mechanical properties of the cement slurry and set cement have been studied which mainly cover such aspects as rheology, fluid-loss of the cement slurry and uniaxial compressive strength (UCS) through experimental measures.

The experimental results indicate that UCS decreases gradually with increasing concentrations of the expanding additive. The density, free fluid, and rheology of cement slurry show consistently with the variation of expanding additive concentration. In addition, the fluid loss will increase relative gradually with the increment of expansive additive concentration. By increasing the concentration of expansive additive from 0% (w/w) to 3% (w/w), cement slurry’s rheological properties consistently behaved as the main properties as plastic viscosity (PV), yield point (YP) and gel strength (GS) of 10-seconds and 10-minutes with values varied around 262.33 cP, 5.25 lb/100ft², 6.33 lb/100ft², and 15.26 lb/100ft² respectively. However, the UCS value behaves contrary to the rheology properties, which gradually decreased from 63.33 MPa to 33.54 MPa with the concentration, increased from 0% to 3%. As the UCS test conducted under the curing conditions as 150 ℃, 3000psi and 24hrs, this gradual decrease of UCS maybe because of the delayed hydration characteristics of micro-MgO. Despite this decrease in USC is not positive to prevent any stressed-induced micro-channel, these results are still interesting for further corresponding study and will make the understanding of MgO based expansive additive’s effect on Portland cement matrix more completely. As per other research results and our future experimental study plan, the delayed expansion of micro-MgO hydration will compensate for the chemical and bulk shrinkage issue after enough curing.

According to the literature review, there are few publications reporting results on micro-MgO based expandable cement systems based on Class G cement.  Through this study, we are expecting to manifest a trend between the concentration of expanding additive and the cement slurry properties. This will provide the technical reference and guidance for further study and application of expanding cement systems in the industry.

How to cite: Chen, W., Mahmoud Elkatatny, S., Murtaza, M., and Abdulhamid Mahmoud, A.: Effect of Micro-MgO-based Expanding Agent on Rheological and UCS Properties of Well Cement at Early Age, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-4511, https://doi.org/10.5194/egusphere-egu2020-4511, 2020.

Salt rocks serve as host rock for technical caverns due to their impermeability but their can also be influenced by fluid migration due to geological fracture zones. Seismic methods can be used to monitor cavernous structures in the transition zone between cavity and undisturbed salt rocks. Around an artificially created cavity (field-test cavern) in a salt pillar with a volume of approximately 100 litre, travel time tomography was utilized to image structures related to caverns and fluid-storage. Seismic surveys were performed at different stages of an experimental simulation of gas-water-rock interaction in the field-test cavern aiming for a better understanding of the multiphase system in the cavern-near area. The baseline survey (1) was carried out using 8 three-component piezo-electrical sensor rods and a seismic vibrator source at the surface of the salt pillar, first without an installed field-test cavern. After drilling and installing the field-test cavern, seismic cross-hole measurements were performed after producing partial vacuum in the test cavern (2) and infill of gas (3) and water (4). To finalize the field experiments the last seismic survey (5) was again conducted at the surface of the salt pillar as a repeat measurement to the baseline survey. The seismic monitoring of the salt pillar was carried out in a frequency range of 100 Hz to 14000 Hz allowing a spatial resolution in the cm-range. This was followed by pre-processing of the seismic data sets to apply the picked travel times in a tomography program. On the basis of the tomography results and reflection seismic data we want to assess the potential enlargement of the field-test cavern due to water-infill and to image the differences between unaffected salt rocks, cavernous structures and developing transition zones.

How to cite: Richter, H., Giese, R., Zirkler, A., and Strauch, B.: Seismic surveys at an artificially created field-test cavern within a salt pillar, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-6843, https://doi.org/10.5194/egusphere-egu2020-6843, 2020.

Wellbore cement integrity under CO2 geologic storage (CGS) conditions is a key factor to assure safe and permanent storage of CO2. Wellbore cement integrity may be impaired and the structure of cement may be altered as a result of CO2 attack. To understand how CO2-induced structure alteration in oil well cement under CGS conditions affects well integrity in CGS projects, this paper reports an experiment of reaction between CO2 and oil well cement under CGS conditions. Samples were scanned by Micro CT before and after reaction. The Micro CT is capable of operating at 140KV and 10W, has a maximum resolution of 10µm. To simulate the reaction between CO2 rich brine and oil well cement at CGS conditions, our team has developed a testing system which provides the storage temperature and pressure. 

The samples were made by standard class G oil well cement used for CGS pilot projects. The cement was cured at CO2 storage formation conditions: 62℃, 17MPa, and 1 wt% NaCl solution. The curing was maintained for 14 days. The diameter of the samples was 10 mm. Every sample contained a small borehole at center (around 1 mm diameter) that made the samples suitable for examining seepage through small leakage pathways within cement. During the reaction experiment, the samples were placed in the high-pressure, high-temperaure testing system for 14 days, given a temperature of 62℃ and a CO2 partial pressure of 17MPa. The goal of this experiment is to evaluate how the geochemical reactions between dissolved CO2 and cement affect structure of the cement. Change of borehole geometry was not observed in the Micro CT images. However, a region with decreased porosity around the borehole due to CaCO3 precipitation and a region with increased porosity around the borehole due to Ca(OH)2 and C-S-H dissolution were observable. Initial distribution of cementitious materials and solution buffering governed the width of the high-porosity region and CaCO3 precipitation region. This study demonstrates a 3-D sample characterization technique that can be used to investigate CO2-induced structure alteration of oil well cement. 

How to cite: Wang, Y., Zhang, L., and Miao, X.: Characterization of CO2 Induced Wellbore Cement degradation by Micro CT, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-7419, https://doi.org/10.5194/egusphere-egu2020-7419, 2020.

Salt deposits may be affected by post-depositional CO₂ intrusions. In central Germany, such CO₂ contributions from the mantle may originate from Tertiary Rhön- and Vogelsberg-volcanism. The intrusion of those gases may cause technical and operational implications for storage caverns and salt mines.

Carbon isotope compositions of CO₂ are useful tools to differentiate between sources and are expressed as δ¹³C values in ‰ versus an international standard known as the Vienna Pee Dee Belemnite (VPDB). Typical average endmember values for CO₂ from the mantle are -5.1 ‰, while background air and anthropogenic influences range around averages of -11.9 ‰ and -29.8‰. Detection of fluctuations between these endmembers can be challenging with discrete sampling. This can be overcome by high-temporal resolution and long-term monitoring.

Towards this purpose, a laser-based isotope system was set up in an active underground salt mine in central Germany. For 34 days, continuous measurements of δ¹³C and concentrations of CO₂ were generated close to a site where mantle CO₂ intrusions were suspected. A timer regularly switched intakes from two capillaries, of which one was placed inside a borehole and the other in ambient air of the mine. Measured CO₂ concentrations ranged between 700 and 1600 ppmV, while δ¹³C values ranged between -21.5 ‰ and -11.5 ‰. Lower concentrations coincided with more positive isotope values and occurred around weekends when anthropogenic influences in the mine were less.

While influences of fresh air venting may have caused these weekly shifts, the admixture of mantle CO₂ seemed to play a continuous role. This is because small differences between the capillary from the borehole and the one with ambient air existed throughout the time series. Our results indicate that short-term dynamics on the order of hours to days are overlain by admixtures mantle gas intrusions of CO₂.

How to cite: Frank, A. H., van Geldern, R., Myrttinen, A., Zirkler, A., Zimmer, M., Barth, J. A. C., and Strauch, B.: Detection of mantle CO2 in an underground salt mine via long-term and high-resolution monitoring by laser-based isotope techniques, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-8197, https://doi.org/10.5194/egusphere-egu2020-8197, 2020.

Carbon Capture and Storage technology is considered to be able to contribute to a carbon neutral society and is again receiving increased attention in the efforts to reduce CO₂ emissions. To ensure safe operation of such CO₂ storage projects, reliable monitoring technologies are required. Due to the generally high electrical resistivity contrast between CO₂ and formation water, Electrical Resistivity Tomography (ERT) can be considered one of the most effective geophysical techniques in the monitoring of CO₂ migration in the subsurface.

Within the ERA-NET co-funded ACT project Pre-ACT (Pressure control and conformance management for safe and efficient CO2 storage - Accelerating CCS Technologies) a CO₂ injection and monitoring experiment was planned at the Svelvik CO₂ Field Lab, located on the Svelvik ridge at the outlet of the Drammensfjord in Norway. The Svelvik field lab consists of four 100 m deep monitoring wells, drilled in July 2019, surrounding an existing well used for brine and CO₂ injection. Each monitoring well is equipped with modern sensing systems including five types of fiber-optic cables, conventional and capillary pressure monitoring systems, as well as 16 ERT electrodes with a spacing of five meters.

With 64 installed electrodes, a large number of measurement configurations is possible. We combine the free and open-source geophysical modeling library pyGIMLI with ECLIPSE reservoir modeling to simulate the expected behavior of all cross-well electrode configurations during a CO₂ injection experiment. Simulated CO₂ saturations are converted to changes in apparent resistivity using Archie's law. Different considerations have to be made to select a suitable set of electrode configurations, i.e. not too large geometric factors, maximum response to the predicted change, as well as sensitivity in the target area. We select sets of configurations based on different criteria, i.e. the ratio between the measured change in resistivity in relation to the geometric factor, the maximum change in apparent resistivity, and maximum sensitivity in the target area. The individually selected measurement schedules are tested by inverting them with different assumed data errors. The numerical results show adequate resolution of the CO₂ plume.

The CO₂ injection took place between 27th October 2019 and 5th November 2019. Approximately two metric tonnes of CO₂ were injected in 65 m depth. Preliminary field results indicate a considerably lower response than predicted by our model. These discrepancies can potentially be explained by oversimplified simulations as well as operational uncertainties. Results from baseline and repeat surveys can therefore support an integrated approach towards a revised static and dynamic model for the test site.

Acknowledgements:

This work was produced within the SINTEF-coordinated Pre-ACT project (Project No. 271497) funded by RCN (Norway), Gassnova (Norway), BEIS (UK), RVO (Netherlands), and BMWi (Germany) and co-funded by the European Commission under the Horizon 2020 programme, ACT Grant Agreement No 691712. We also acknowledge industry partners Total, Equinor, Shell, TAQA.

Finally, we thank the SINTEF-owned Svelvik CO₂ Field Lab (funded by ECCSEL through RCN, with additional support from Pre-ACT and SINTEF) for assistance during installations and for financial support.

How to cite: Raab, T., Weinzierl, W., Rippe, D., Wiese, B., and Schmidt-Hattenberger, C.: Electrical Resistivity Tomography Concept for CO2 Injection Monitoring at the Svelvik CO2 Field Lab, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-9402, https://doi.org/10.5194/egusphere-egu2020-9402, 2020.

Fluid inclusions are voids enclosed in the rock matrix and contain, depending on their origin and development, various amounts of gaseous, liquid or solid phases. Depending on their occurrence within the crystalline structure or in healed micro-fractures, primary and secondary inclusions can be distinguished. Their characteristics are utilized in various geological settings to reconstruct rock history and fluid involvement. Fluid inclusions could also be considered to be small equivalents to large cavities. As salt is regarded a favorable host rock for the storage of natural gas and other materials in artificial caverns, knowledge on gas migration and retention is crucial.

Here, we present results of a fluid inclusion study in various salt rocks using Raman spectroscopy in addition to conventional microscopic characterization and gas analysis on whole rock samples. This approach allows for a better understanding of fluid generation and migration in different salt lithologies over geological times.

Various salt minerals (halite, sylvite, kieserite and carnallite) from an area of potential overprint of CO₂-dominated gas migration were investigated. Numerous fluid inclusions exhibit chevron structure and are small sized. Large single- or two-phased inclusions are observed with irregular shapes, often indicative for leakage or necking down. Interestingly, although the CO₂ concentrations in whole rock samples were high, fluid inclusions were dominated by an aqueous phase and often contain numerous daughter minerals. This suggests that CO₂-rich gas is stored along distinct fractures or grain boundaries within an otherwise intact rock.

How to cite: Strauch, B., Zimmer, M., and Zirkler, A.: The hidden CO2 - The occurrence, distribution and composition of fluids in various salt minerals, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-10335, https://doi.org/10.5194/egusphere-egu2020-10335, 2020.

Estimations of CO₂ storage capacities for saline aquifers, particularly the Utsira Formation (northern North Sea) have previously been calculated using a variety of numerical approaches. These are mainly based off reservoir depth maps and averaged petrophysical properties. In these first-pass estimations, a thick shale succession in the overburden is assumed to form the top seal. This is unlikely to be representative of the true, regional lithological heterogeneity and 3D variability of stratigraphic architecture, which may promote CO₂ migration out of the reservoir during injection.

This study utilises a recently acquired regional high-resolution 3D broadband seismic dataset (37,500 km²) and >200 wells in the North Viking Graben, with the aim to fully characterise the overburden of the potential CO₂ reservoir (Northern Utsira Formation). The objectives are to analyse: i) the presence and spatial extent of sandstone bodies in the overburden and their connectivity with the reservoir; ii) the presence of sand-filled slope channels on the clinoform foresets that may act as migration pathways; iii) evidence of previous fluid migration through the overburden. Manual seismic interpretation and well correlation is augmented by automated horizon propagation (Palaeoscan) to map individual clinoforms across the region. This is integrated with seismic attribute analysis, frequency decomposition and automated well lithology extraction to understand regional sand distribution and feature analysis (e.g. identification of channels and their fill, and possible shallow gas).

Large fan-shaped sandstone bodies (10s km-scale) are identified in the lower foresets and bottomsets of the clinothems. In the west, these are in connection with the Utsira Fm., or separated from it by a thin (<10 m) shale layer. These sands can be both beneficial to the storage capacity by producing additional gross reservoir volume (if sealed and below the critical depth for CO₂), or detrimental to it if they provide a path to bypass the Utsira Fm. top seal. In the south east, sand-filled slope channels and lobes (km-scale) are recorded in the prograding clinothems but are not observed to be in connection with the Utsira Fm. (located >100 m above top Utsira Fm.). No sand-filled channels were identified in the north east from seismic attribute analysis, however the well lithology extraction for this region contained ~3% sand, thus there is a possibility of sub-seismic resolution features. In the south, foresets directly downlap the Utsira Fm. This geometry juxtaposes several individual clinothems against the reservoir, increasing the likelihood of migration if there is sand presence. This contrasts with the scenario in the north, where the bottomset of a single clinothem disconnects the reservoir from younger clinothems and restricts potential migration.

The outcome of this study is an integration of each of the regional feature maps to generate: i) a seal thickness map between the Utsira Fm. and the first overlying sand body; ii) the first leakage risk map of the Utsira Fm. that captures geological geometry and lithology distribution. These can be incorporated into any future storage estimations and identification of potential injection sites.

How to cite: Lloyd, C., Huuse, M., and Barrett, B.: Regional seal characterisation for CO2 storage, Northern North Sea, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-10725, https://doi.org/10.5194/egusphere-egu2020-10725, 2020.

Slow groundwater flow and mass transport processes in mudstone sometimes exhibit non-Darcian flow. For example, it is known that some mudstone shows semipermeable properties because of its negative charge of clay minerals and narrow pore throats (Marine and Fritz, 1981). In such formations, osmotic flow, water flow driven by osmotic pressure, occurs and it induces pore pressure change in low-permeability or hydraulically isolated area (Marine and Fritz, 1981). If large pore-water concentration difference exists in tight and clay-rich formation, osmosis-induced pore pressure can reach to about 20MPa(Neuzil, 2000). Change of pore pressure causes deformation of porous medium.  Osmosis-induced pore pressure change can cause deformation of porous medium (Greenberg et al., 1973: Noy et al., 2004) and it is possible that large concentration difference causes rock deformation or destruction in semipermeable formations.

The purpose of this study is to establish a model which describes pressure behavior, solute transport, and deformation of semipermeable mudstone and to discuss the validity of the model through comparing the model result and the results obtained from laboratory experiments. The numerical model is established by coupling the equations of solute transport and pressure behavior in semipermeable mudstone(for example Malusis et al., 2012), and that of poroelasticity (for example Wang, 2000). For laboratory experiments, core samples with 50mm in diameter and 30mm in height were prepared from mudstone samples collected from Neogene formation in Japan. NaCl solution with 10 g/L higher than that of pore water was contacted to one of the surfaces of the sample, and all the other surfaces were sealed with silicone rubber. Longitudinal deformation of the sample surface was measured. Here, optical fiber sensing technique was used to measure strain behavior, and hence, it was possible to measure strains at multi point of the sample. The measurement was continued more than 240hr.

In the presentation, the comparison of results obtained from experiments and calculations will be shown and the significance will be discussed.

How to cite: Hirota, S., Tokunaga, T., Aichi, M., Xue, Z., and Park, H.: Coupled chemical osmosis and rock deformation processes in semipermeable mudstone- theoretical and experimental approaches-, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-13798, https://doi.org/10.5194/egusphere-egu2020-13798, 2020.

A potential solution to reduce the emission of CO₂ in the atmosphere is to store CO₂ in subsurface reservoirs. This may be in depleted gas/oil reservoirs, saline aquifers or other porous geological formations, both on shore and off shore. To avoid any hazardous incidents, it is of high importance that the reservoirs can be proven leak free and that there is a good communication within the reservoir.

A useful tool to determine the storage quality of a reservoir is to use Strontium Residual Salt Analyses (Sr-RSA). This is an efficient tool to determine the fluid connectivity of the reservoir and the caprock in horizontal and lateral directions. In addition, it can reveal the presence of barriers and baffles in a geological perspective. Sr-isotope data can also be used to calculate the extent of the barriers and moreover, use of Carbon and Oxygen isotopes measured in cemented barriers can help reveal the history of the barriers (time and temperature of the cementations).

The Geochemistry laboratory at Institute for Energy Technology (IFE) has partially been financed by Horizon 2020 and is a part of the ECCSEL infrastructure. The multi collector (MC)-ICP-MS at IFE’s Geochemical Analysis Lab performs high-precision, high-resolution, and simultaneous measurements of isotope ratios in a wide range of isotope systems. Other Isotopes systems of interest for characterize CO2 storage reservoirs, traditional and non-traditional stable and radiogenic isotopes (Sr, Pb and U, Li, Mg, Ca, Mg, Fe, Cd, Cu, Zn, and Ni), geo- and thermo-chronology, tracing fluid flow patterns, fingerprinting sources of materials, quantifying interactions in biogeochemical systems, and monitoring environmental systems.

By coupling the MC-ICP-MS to IFE’s LA-HR-ICP-MS, the simultaneous analysis of novel isotopes and trace elements in solid materials can be achieved. The laboratory is a state-of-the-art facility for measuring isotope systems to produce data to interpret: biogeochemical reaction rates and products, tracking fluid migration, evaluating fluid/rock interactions and detect CO₂ leakage in cap rock.

How to cite: Johansen, I., Huq, F., Schöpke, C. A., and Yarushina, V.: ECCSEL Infrastructure for Isotope Characterization of Reservoirs for Subsurface CO2 Storage, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-15260, https://doi.org/10.5194/egusphere-egu2020-15260, 2020.

Underground storage of hydrogen (H2) could be an alternative or important supplement to energy storage. However, there is still lack of knowledge about fundamental biogeochemical aspects of underground H2 storage. The BMBF-funded project H2_ReacT investigates fundamental petrophysical, geochemical and biogeochemical aspects of underground H2 storage. The work presented here addresses the microbial consumption of H2 and the involved microorganisms at potential underground storage sites.

Microbial reactions that consume H2 are still a major uncertainty factor for underground H2 storage. Microbial life is widespread in the crust of the earth and geological formations suitable for underground H2 storage often contain a deep subsurface biosphere. Thus, an underground H2 storage site needs to be seen as a habitat for microorganisms. Microbial activity at the H2 storage site might affect the stored H2 as well as the integrity of the storage site itself. A specific interest is to gain information about microbial activity that might result in a loss of stored hydrogen as well as the production of unwanted metabolic products e.g. H2S. The importance of specific conditions with relevance for underground hydrogen storage i.e. elevated pressure, high temperature and rock material, will be addressed.

Preliminary results showed the consumption of H2 by indigenous microorganisms from a porous rock reservoir fluid. Hydrogen was consumed at different temperature and pressure conditions relevant for underground H2 storage. Here, hydrogen consumption rates were strongly influenced by temperature and pressure. Currently effects of several geochemical parameters on microbial H2 consumption are studied in more detail. Furthermore, molecular biological approaches are used to identify the involved microorganisms.

How to cite: Krueger, M. and Dohrmann, A.: Microbial Redox Reactions During Underground Storage of Hydrogen, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-18434, https://doi.org/10.5194/egusphere-egu2020-18434, 2020.

The potential role of hydrogen in achieving a net zero emissions future is gaining traction. A hydrogen economy would likely be supported by geological formations in which to store hydrogen at times of excess and to extract in times of demand, akin to subsurface natural gas storage.

Minimising the risk of hydrogen leakage is not only important to support the safety case for geological storage, but also to constrain risk of any economic losses from the migration of hydrogen from its intended storage formation. As such, deepening scientific understanding of the processes governing hydrogen containment and leakage is fundamental for: (a) prospecting of natural hydrogen plays, (b) informing effective site selection for geological hydrogen storage, and (c) the design and performance requirements of appropriate monitoring of these sites.

Several earth processes generate hydrogen, and naturally occurring subsurface hydrogen accumulations and hydrogen seeps (where hydrogen is seeping to surface) present opportunity for study to further knowledge on geological containment of hydrogen. Here, we present a synthesis of the available literature on natural analogues for hydrogen storage and seepage around the world to elicit the factors governing containment/leakage and seep characteristics. We also consider how learnings from other subsurface energy sectors such as geological CO₂ storage might be translated and applied to hydrogen storage.

We find that currently there are few natural analogues for hydrogen – there are only eight hydrogen seeps and fewer hydrogen accumulations documented in the scientific literature (though we postulate that other sites of hydrogen accumulation and seepage may exist but are yet to be documented). For all known analogues, the hydrogen is thought to derive from deep seated processes (e.g. serpentenization) rather than superficial bacteriological or other processes. Hydrogen seepage can occur in clusters or in isolation, and the location, distribution and morphology of seeps are controlled by geological factors such as regional stress, occurrence of faults, and properties of the host rock. These factors are similar to those governing CO₂ seepage, but we note differences, too. One documented hydrogen accumulation is shallow (80-150m). Hydrogen and methane occur in different proportions at different depths in the reservoir complex. This implies that different rock properties constitute a seal/reservoir for methane and hydrogen. The parameters that define a hydrogen “play” may therefore be different to a hydrocarbon play.

Overall very little is known about how hydrogen migrates and is trapped in the subsurface, and there are few studies of natural analogues. Our work highlights the need for further research around the factors that govern hydrogen fluid flow, and thus the degree to which knowledge of fluid flow of other geofluids can be translated and applied to ensure effective and secure geological hydrogen storage.

How to cite: McMahon, C. J., Roberts, J. J., Johnson, G., Shipton, Z. K., and Edlmann, K.: Geological Storage of Hydrogen: Learning from natural analogues, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-18548, https://doi.org/10.5194/egusphere-egu2020-18548, 2020.

Geological carbon storage (GCS) has been identified as a crucial process in tackling rising anthropogenic CO₂ emissions. We examine 4 sandstone cores from the Scottish Middle Coal Measures Formation at the UK Geoenergy Observatories (UKGEOS) site in Glasgow using X-ray micro computed tomographic images to assess the carbon storage capacity. Each 3D microtomographic image was processed by binary segmentation to extract the macroporosity from the greyscale images, pore network analysis to establish the effective porosity, and permeability simulation using a finite volume solver. We compare this location to 7 samples from the Wilmslow Sandstone Formation in Sellafield as a precursor analysis of the laterally equivalent Sherwood Sandstone at the under construction Cheshire UKGEOS site. We find a significant difference in porosity and permeability between the two sites with Sellafield samples showing a porosity range of 9.73-25.31% whilst Glasgow samples display a range of 0.38-1.65%. The Sellafield samples also show a significant proportion of connected porosity ranging between 8.85 and 25.26%, whilst no connected porosity was found in the Glasgow samples. This is deemed due to the presence of a ubiquitous cement phase occupying up to 26.28% of the sample volume, significantly reducing the viability for fluid injection and therefore GCS at the Glasgow site. Carbon storage is dependent on the availability of pore space for mineralisation and the pore connectivity which allows for fluid flow of CO₂. Our measured values of porosity and permeability also indicate that the Sellafield site and sandstones similar to the samples from this site will be highly effective as CCS target formations.

How to cite: Payton, R. L., Fellgett, M., Kingdon, A., Clark, B., and Hier-Majumder, S.: Pore Scale Analysis of Suitability for Geological Carbon Storage, Implications for the UK Geoenergy Observatories Project, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-18982, https://doi.org/10.5194/egusphere-egu2020-18982, 2020.

Underground hydrogen storage (UHS) in porous media has been proposed as an effective and sustainable energy storage method to balance renewable energy supply and seasonal demand. To determine the potential for and conduct realistic risk assessments of the UHS technology, learnings from more mature underground fluid storage technologies, such as underground storage of natural gas (UGS) or CO₂ (UCS), can be used. Here we discuss the caveats related to the use of these technologies as analogues to UHS and highlight current knowledge gaps that need to be addressed in future research to make UHS a secure and efficient technology.

Abiotic and biotic reactions between the rock and the fluids, often not considered in UCS and UGS operations, play an important role in UHS and can change the chemical environment in the reservoir dramatically. The mineralogy of the reservoir and cap rocks, as well as the in-situ pore fluid chemistry, is of vital importance and the characterisation efforts should not be limited to the reservoir quality.

The risk assessment of UHS operation may follow similar production cycles as in UGS, but there are important lessons to be learnt from UCS. UCS aims to store injected gas permanently and different CO₂ trapping mechanisms are contributing to storage security. Residual trapping, which locks parts of the CO₂ within the pore space, may reduce the commercial profitability in UHS, but can assist to mitigate potential leakage of hydrogen. The dissolution of hydrogen in the pore water will likely play a minor role in UHS compared to UCS, while the precipitation of minerals containing hydrogen during UHS has not yet been appropriately investigated.

The main storage process in gas storage is the accumulation of buoyant fluid underneath a low-permeability cap rock in a three-dimensional trap. Storage sites are determined by different parameters: UGS is mainly used in depleted gas fields (hence sites with proven gas storage security), while UCS sites are usually located deeper than 800m for efficiency reasons, under conditions at which CO₂ is present as a high-density supercritical phase. None of these restrictions are a pivotal for UHS and a new set of constrains should be formulated specifically designed to the properties of hydrogen. These must involve:

• The unique properties of hydrogen (high diffusivity and low density and, thus, high buoyancy) require potential storage sites to have well-understood cap rocks with minimal diffusion and capillary leakage risk.
• A reservoir architecture and heterogeneity that guarantees economically sensible injection and withdrawal rates by choosing sites, which minimise the isolation of hydrogen from the main plume during UHS operations.
• Site monitoring protocols will also need to be re-evaluated for different scales, as well as for the dynamic properties of hydrogen, such as low density and fluid mobility.

It is certain that leakage along abandoned wells, the main risk for leakage in UCS and UGS, will also pose a risk to the containment of injected hydrogen. Therefore, hydrogen storage site locations require a comprehensive investigation into abandoned and operational (deep) petroleum and (shallow) water exploration and production wells.

How to cite: Alcalde, J., Heinemann, N., Bentham, M., Schmidt-Hattenberger, C., and Miocic, J.: Hydrogen storage in porous media: learnings from analogue storage experiences and knowledge gaps, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-19141, https://doi.org/10.5194/egusphere-egu2020-19141, 2020.

The Triassic continental succession located in the eastern side of the Horda Platform (northern North Sea) represents a potential supplementary CO₂ storage formation to the principal Jurassic sandstones above. Several 1-2.5 kilometer-thick packages of Triassic sediment lie within a series of large eastward-dipping half-grabens east of the Viking Graben. The deeply buried Triassic deposits (1.8-3 km) within the prospective area are confined between the Øygarden Fault Zone to the east and the Vette Fault Zone to the west, the latter separating the prospective area from the Troll hydrocarbon fields. Despite extensive petroleum exploration within the Horda Platform, the entire Triassic interval remains largely untested and its storage potential poorly understood. The lack of wellbore penetrations and 3D seismic coverage means that reservoir quality can only be assessed using conceptual predictions and analogue studies.

A seismic stratigraphic model is built using available 2D and 3D seismic and integrated well log data to discern the Triassic basin fill history and structural development of the area. The stratigraphic succession is subdivided into seismic facies, where reflection patterns infer depositional characteristics. A shift in log facies trend between mud- and sand-rich intervals indicates a variance in subsidence rate and sedimentation supply related to tectonic displacement rate and climate. Visual analyses of the seismic data along key horizons also reveal depositional features such as channels, hanging wall fans, and footwall fans. The location and distribution of the channels are mapped in order to assess the connectivity of possible storage bodies.

Analogous Triassic sandstone reservoirs of the Snorre field (Tampen Spur) roughly 125 km away are similar in terms of stratigraphic facies and mineralogy. The Snorre field reservoirs are dominantly subarkosic and arkosic sandstones with illite-smectite and chlorite-smectite and lesser amounts of kaolinite and chlorite clay minerals within the matrix and pore spaces. Furthermore, the Triassic succession is composed of sandstones and mudstones deposited in fluvial systems with subordinate alluvial plain environments. The sandstones possess highly variable poro-perm values closely related to the depositional facies. As the Horda Platform sediments were deposited more proximal to the source than those of the Tampen Spur, it is expected that coarser grain sizes persist within the prospective interval, but perhaps at a lower degree of maturity and higher grain size variability. Overall, this preliminary assessment suggests that thick Triassic channel sandstones present in the eastern Horda Platform have promising CCS potential.

Keywords. Triassic, Horda Platform, CCS, basin fill history, seismic facies, tectonic displacement, climate, reservoir quality

How to cite: Würtzen, C., Nystuen, J. P., Müller, R., Osmond, J., Faleide, J. I., and Midtkandal, I.: CCS potential of the Triassic alluvial succession in the eastern Horda Platform , EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-20701, https://doi.org/10.5194/egusphere-egu2020-20701, 2020.

Increasing atmospheric CO₂ concentration will continue to be a risk if we continue to use fossil fuels as our main energy source. Hydrogen is the ideal low carbon fuel/energy vector to replace fossil fuels facilitating the energy transition, without further increasing gas atmospheric CO₂ concentrations. Thermodynamic characterisation of hydrogen and hydrogen mixed gases is important to solve the challenging production and storage issues in a hydrogen-based economy. Thermodynamic characterisation is vital to design more efficient and more economic production and storage processes, and must be undertaken as a crucial first step for wide application of hydrogen-based fuels and their storage. Here we applied a highly accurate equation of state, namely, GERG-2008, to predict various thermodynamic properties (e.g. phase behaviour, density, viscosity, compressibility, and heat capacity) of hydrogen when mixed with other gases including: CO₂, CH₄, N₂, and natural gas. Given the important influence of other constituents in the hydrogen gas stream on the thermodynamic properties of hydrogen, such thermodynamic data could be used for efficient design, development, and deployment of innovative hydrogen production, transport, blending and storage techniques. Understanding the thermodynamic characterisation of hydrogen and hydrogen mixed gasses is particularly important for geological hydrogen storage, where the thermodynamic properties of the injected gas in equilibrium with existing fluids in the storage reservoir is required to estimate the storage capacity. The data is provided over wide range of pressure, temperature, and molar combination representing the range of fuel blending, applications and storage conditions for hydrogen.

How to cite: Hassanpouryouzband, A., Edlmann, K., Heinemann, N., and Wilkinson, M.: Thermodynamics of Hydrogen-mixed gases, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-20843, https://doi.org/10.5194/egusphere-egu2020-20843, 2020.

As most of the industrial nations are located in the moderate climate zone with distinct summer and winter, global heating and cooling supply is less a matter of energy shortage than an issue of seasonal storage. Aquifer Thermal Energy Storage (ATES ) is capable of storing large energy volumes to bridge the seasonal mismatch between demand and supply of heating and cooling systems. However, there is a discrepancy in global ATES development, since more than 80 % of all ATES system are currently operating in the Netherlands and Scandinavia, which is mainly attributed to techno-economic barriers. Thus, this work analyses the technical performance of ATES based on monitoring data from 73 low temperature Dutch ATES systems. The analysis reveals total abstraction of 30 GWh of heat and 32 GWh of cold per year with average abstraction temperatures of 10 °C and 15 °C in summer and winter, respectively. However, while the temperature difference between abstraction and injection is 3-4 K smaller compared to the optimal design, the stored and abstracted amount of thermal energy is 50 % lower than the licensed capacities. This suggests inadequate interaction between the energy system and the aquifer as a result of the insufficient charging process of the subsurface. Nevertheless, the data showed only small thermal imbalances and small temperature losses during the storage period. Based on the comprehensive analysis, valuable conclusions can be drawn on the optimizations needs of current and future ATES projects.

How to cite: Schüppler, S., Fleuchaus, P., Godschalk, B., Bakema, G., Zorn, R., and Blum, P.: Aquifer Thermal Energy Storage (ATES) systems - current global practical experiences , EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-21396, https://doi.org/10.5194/egusphere-egu2020-21396, 2020.

Precaspian basin is the most petroliferous basin in Kazakhstan with more than 100 years of history of the oil and gas industry. The economy of the country has been depending on the revenues coming from the sale of Precaspian oil. Nevertheless, the average oil recovery rate in the country remains low around 30-35% and its government planned to increase the recovery rate to 55-60%. The high oil recovery rate could be achieved by enhanced oil recovery (EOR) methods by injecting diverse inert gases and liquids. The global challenge of excessive CO₂ emissions makes an EOR with CO₂ injection (CO₂-EOR) a good candidate because the anthropogenic CO₂ emission could be a good source of the injection gas. Depleted oil reservoirs are the first targets for the implementation of carbon storage. The basin contains 178 oil and gas fields distributed in pre-salt and post-salt sections divided by the huge Kungurian salt bed that deformed into domes throughout the basin. A set of suitable reservoir parameters (Original Oil In Place (OOIP), depth, API, pressure, porosity, permeability, initial oil saturation) for CO₂-EOR have been identified by earlier works of researchers based on previous experience of the petroleum industry and used to screen the oil reservoirs of the Precaspian basin. Thirty-four reservoirs of the basin were identified to be suitable for CO₂-EOR or CO₂ storage. The effective CO₂ storage capacity of the reservoirs has been estimated using the Carbon Sequestration Leadership Forum (CSLF) method. The previous estimation of the storage capacity of 178 reservoirs was 179.2 Mt of CO₂ however, after the CO₂-EOR screening, the capacity decreased to 24.4 Mt. The mapping of CO₂ sources and investigation of CO₂ amount released from each CO₂ source in the Precaspian basin will contribute to the CO₂ source-CO₂ sink matching to decide the most feasible CCS options. In addition, the analysis of fault intensity and seismicity in suitable reservoir-seal pairs could have important implications for the safety of CO₂ storage.

How to cite: Seisenbayev, N., Abuov, Y., Tolenbekova, Z., and Lee, W.: Assessment of CO2-EOR and its geo-storage potential in oil reservoirs of Precaspian basin, Kazakhstan, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-21528, https://doi.org/10.5194/egusphere-egu2020-21528, 2020.

Carbon Capture and Storage (CCS) can provide the solution for the impending challenge of climate change until Renewable Energy Sources (RES) can take over a significant role in global energy market. Kazakh government developed the “Green Economy” plan to increase the share of RES in the energy sector to 50% by 2050. In November 2016, Kazakhstan ratified Paris Agreement to cut its GHG emissions from the base year of 1990 by 15% and 25% under different conditions. Previous research efforts in TIMES energy system modeling of GHG emissions has shown that satisfying the Paris Agreement terms require full phasing out of coal from residential sector heating in favor of RES. Given the current 1% share of RES in the energy sector, the energy demands of the country cannot be met with coal being excluded from consumption. Given the large fossil fuel resources of the country and coal-dependent economy, CCS may play a major role in the decarbonization of the country while allowing to rely on coal. “KazCCUS” is the first CCS-related project in post-soviet countries which aims to develop CCS related technologies in Kazakhstan. This research aims to identify proper geologic structures in sedimentary basins and estimate their storage capacity. Governmental oil and gas field database that was compiled from field operator surveys and publicly available literature was used to identify horizons with suitable reservoirs-seal characteristics. CO₂ storage options were identified in 6 sedimentary basins of the country: Preacaspian, Mangyshlak, Ustyurt, South Torgay, Chu-Sarysu and Zaysan basins. The effective CO₂ storage capacity in oil reservoirs, gas reservoirs and saline aquifers were estimated using the methods developed by Carbon Sequestration Leadership Forum and US DOE. The total effective CO₂ storage capacity in 6 basins was  estimated to be 204 Mt, 610 Mt, and 403 Gt in oil reservoirs, gas reservoirs, and saline aquifers, respectively. Sedimentary layers without intense faulting and suitable reservoir-seal pairs were found in 4 petroliferous sedimentary basins. The carbonate platforms in the pre-salt section of Precaspian basin and post-salt clastic reservoirs trapped by salt-dome related traps provide potential storage sites for CO₂. Jurassic sandstone successions in Mangyshlak, South Torgay and Ustyurt basins are also good candidates for geologic CO₂ storage and they all have a thick seal or caprock system that were holding hydrocarbon fluids for geologic time scale. The results of this study suggest that there is a huge potential for CCS in Kazakhstan and CCS can be deployed in mature fields of oil-producing basins. In addition, CO₂-EOR is an option for operating oil fields. The country can have both environmental and economic benefits from CO₂ storage and this will also contribute to the compliance with Paris Agreement terms. This research may serve as a baseline for future CCS deployment strategy in Kazakhstan.

How to cite: Abuov, Y. and Lee, W.: CO2 storage capacity of Kazakhstan, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-21554, https://doi.org/10.5194/egusphere-egu2020-21554, 2020.

The ECCSEL Svelvik CO2 Field Lab is a test site for shallow CO2 injection operated by SINTEF, where the aim is to improve monitoring techniques and extend the knowledge base for storing CO2 underground in deep saline aquifers as a climate mitigation strategy. The test site is located in a Holocene ice contact deposit near Drammen in the Oslofjord. Test injection is possible at 65 m depth. There has been extensive research focused on increasing the understanding of monitoring methods for deep injection of CO2 and the (short term) migration of CO2, based on experiments performed in this shallow aquifer. To maximize the value of data collected in the shallow experiments a solid geological model is fundamental to enable prediction of how water and gas will behave in the reservoir. Various thicknesses of reservoir layers and degree of internal heterogeneity (clinoforms, unconformities, faults) are observed. Analysis of new data from wells (cuttings sediment samples, wire line logs) and comparison with existing data (e.g. seismic lines, georadar profiles) indicate upwards shallowing and upwards freshening trends through the stratigraphic succession, i.e. variation in palynomorph assemblages. Groundwater flux and aquifer connectivity was evaluated through comparison of water chemistry, noble gas content (the ICO2P project) as well as resistivity- and pressure-logging in upper (fresh) and lower (saline) parts. Analysis of the tidal pressure signal in the deep part of the aquifer gives an indication of the degree of communication between the layers of the aquifer. The areal extent of (semi-)sealing layers of mud, as well as intra-reservoir geological heterogeneity (inclined, graded sandy beds with thin, muddy lamina) affects CO2 distribution in the test reservoir, and is likely to lead buoyant fluids along preferential flow paths. Facies models include North-South progradational patterns and are represented in anisotropic property distributions (Petrel - Schlumberger) for fluid flow simulations (Eclipse - Schlumberger). Predicted CO2 flux is towards the North, below what appears to be locally extensive flow baffles. Integrated data analysis has improved the geological understanding of the Svelvik stacked aquifer system, which may be utilized in future applications to improve monitoring methods for safe large-scale CO2 storage.

How to cite: Sundal, A., Grimstad, A. A., Weber, U. W., Kurschner, W., Hagby, K., and RIngstad, C.: Effects of geological heterogeneity on fluid distribution and pressure propagation in a shallow, stacked aquifer system at the ECCSEL Svelvik CO2 Field Lab, Norway, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-21758, https://doi.org/10.5194/egusphere-egu2020-21758, 2020.

The ECCSEL Svelvik CO₂ Field Lab outside Oslo has been set up for water and CO₂ injection experiments. At the site, ongoing and future investigations on monitoring techniques for carbon capture and storage (CCS) shall support the development of CCS as a climate change mitigation technology in Norway.

In 2019, four 100 m deep injection wells with a sophisticated physical monitoring setup were established. For chemical monitoring a fluid sampling system at injection depth was installed and coupled to a continuously measuring mass spectrometer for observing CO₂ distribution. Alongside, a network of soil gas flux chambers (LI-COR 8100) were set up to monitor possible surface leakages.

The field lab is placed in a sand quarry within the Svelvik Ridge consisting of Holocene, siliciclastic sediments. Injection is conducted into a saltwater aquifer at 65m, supposedly sealed by clay strata. We sampled the upper fresh water aquifer at 6.5m depth and the storage aquifer at 64 - 65 m depth on dissolved gases before injection in order to design a noble gas tracer for the CO₂ injection experiment. Elevated helium concentrations in the saline aquifer indicate natural radiogenic accumulation; meanwhile krypton concentrations were not naturally increased.

During an injection experiment in fall 2019, we added noble gases, i.e. krypton and helium, in two subsequent injection cycles, three days and one week, respectively. Outgassing was observed and high helium concentrations verified a leakage at the injection well, which we quantified with a flux chamber.

How to cite: Wolfgang Weber, U., Heeschen, K., Zimmer, M., Raphaug, M., Hagby, K., Ringstad, C., and Sundal, A.: Tracer Design and Gas Monitoring of a CO2 Injection Experiment at the ECCSEL CO2 Field Lab, Svelvik, Norway, EGU General Assembly 2020, Online, 4–8 May 2020, EGU2020-18150, https://doi.org/10.5194/egusphere-egu2020-18150, 2020.