ERE3.1

The SHARP project was launched in late 2021 as a collaboration between 16 research institutions and commercial companies in Norway, UK, the Netherlands, Denmark, and India under the ACT3 Programme. The project is interdisciplinary with a strong focus on understanding and reducing the uncertainties related to subsurface CO₂ storage containment risk focusing on the geomechanical aspects of CO₂ storage.

The geomechanical response to CO₂ injection is one of the key uncertainties in assessing proposed storage sites. The main aim of the SHARP project is to mature the technology for quantification of subsurface deformation by the development and integration of models for subsurface stress, rock mechanical failure and seismicity. Key activities for the project include: developing basin-scale geomechanical models that incorporate tectonic and deglaciation effects and use newly developed constitutive models of rock/sediment deformation (WP1);  improving knowledge of the present-day stress field in the North Sea from integrated earthquake catalogues and developing a database of earthquake focal mechanisms (WP2); quantifying rock strain and identifying failure attributes suitable for monitoring and risk assessment using experimental data (WP3); developing more intelligent methods for in situ monitoring of rock strain and failure as part of the overall monitoring programmes (WP4); quantifying containment risks using geomechanical models and observations from the field and laboratory (WP5); and communicating technology development on containment risk to industry and regulators (WP6).

The SHARP project is expected to accelerate the maturation of six sites from the North Sea region and India. The case study sites range from very mature projects such as the Northern Lights CO₂ storage project in the Horda area (N) to emerging storage prospects such as the Endurance site (UK) and the Hanstholm structure (DK). Furthermore, application of the methods to well-characterised offshore depleted oil and gas fields as Nini (DK) and Aramis (NL) will accelerate their transformation into viable and safe CO₂ storage sites. India has high focus on emission reduction including development of CCUS and an onshore case study for CO₂ injection will be matured using lessons learned from the European projects in order to kick-start CO₂ injection and storage projects in India.

Involvement of international CO₂ storage operators in the consortium ensures that the SHARP project has a high impact on CCS development in Europe and India, as well as globally. New technologies for quantification of subsurface deformation and strategies for monitoring deformation and fluid flow will provide cost-efficient tools for CO₂ subsurface risk management. The results of the project will be communicated to storage site operators and regulators to increase confidence in storage safety and seismicity risk assessment.

How to cite: Larsen, T. B., Skurtveit, E., Ringrose, P., Hindriks, K. K., Kühn, D., Roberts, D., Kendall, J. M., Keiding, M., Barnhoorn, A., and Singh, D. N. and the SHARP Team: Stress history and reservoir pressure for improved quantification of CO2 storage containment risks (SHARP Storage), EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-1787, https://doi.org/10.5194/egusphere-egu22-1787, 2022.

Gas leakage from deep geologic storage formations to the Earth’s surface is one of the main hazards in geological carbon sequestration and storage. Permeable sediment covers or natural and artificial pathways, such as faults and well structures, are the main factors controlling surface leakages. Therefore, the characterization of natural systems, where large amounts of CO₂ are released, can be helpful for understanding the effects of potential gas leaks from storage carbon systems. In this framework, we propose a combined use of geoelectrical investigations (i.e., resistivity tomography and self-potential surveys) for characterizing natural CO₂ leakage areas, as well as gas storage sites. Such methodologies appear to be among the most suitable for revealing spatial distributions of carbon dioxide and monitoring subsurface fluid migration processes, because of the strong dependence of the electrical properties of water-bearing permeable rock, or unconsolidated materials, on many factors relevant to CO₂ storage (i.e., porosity, fracturing, water saturation, etc.). Indeed, the electric resistivity of porous water-bearing sediments decreases significantly when CO₂ dissolves in pore-water, in contrast to the effect in the gas phase and supercritical CO₂, while the anomalous concentrations of natural electric charge are directly related to carbon dioxide migration along porous and fractured rock systems. The effectiveness of the suggested multi-methodological geoelectrical approach is tested in some areas of natural CO₂ degassing located in the Southern Apennines (Italy), which could represent natural analogues of gas storage sites. Specifically, electrical resistivity and self-potential surveys are targeted at reconstructing shallow buried fracture networks in the cap-rock and detecting preferential CO₂ migration pathways. Our findings are promising for imaging the CO₂ plume within a carbon storage reservoir and for identifying possible CO₂ leakages through the cap-rock formation, suggesting that the proposed approach can be very helpful also for the monitoring of carbon sequestration systems.  

How to cite: Salone, R., De Paola, C., Ferranti, L., and Di Maio, R.: Understanding the effects of leaking gas in geological carbon sequestration through geophysical characterization of natural CO2 gas emission systems, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-2440, https://doi.org/10.5194/egusphere-egu22-2440, 2022.

Recently, CO₂ storage has become one of the most effective ways to counteract greenhouse gas emissions and contribute to the global carbon neutrality agreement. To ensure containment, it is important to know how geological layers surrounding the targeted reservoirs will serve as a seal to injected fluids, in particular where the overburden and reservoirs are affected by faults. One of the main controlling factors for gas leakage is through fault networks. Studying worldwide areas of natural gas emission is therefore useful in understanding the risk of potential gas leakage associated with CO₂ storage. From a range of geological scales, reviewing cases of natural gas leakage through in-house and published datasets, can help us understand the various geological factors which influence a region to be more or less susceptible to vertical fluid escape. In this study, a review of CO₂ and CH₄ (Methane) surface leaks is mapped using Geographical Information Systems (ArcGIS Pro). Moreover, a relationship between CO₂ and CH₄ leakages and the global strain map, stress map, heat flow maps, and world lithologies is generated. Strain rates and deformation styles are based on the global strain rate map of Kreemer et al. (2014). Plate boundary zones are defined and categorized into extensional, transtensional, strike-slip, transpressional and compressional settings. Deformation styles associated with these categories are represented between values 1 and -1 respectively. Furthermore, numerical values of the strain rate are divided into three classes: high, low, and negligible deformation rates. Stress regimes independently derived from the world stress map dataset (Heidbach et al., 2018) are generally consistent with deformation styles in the high and low deformation rate zone and provide additional constraints in the plate interiors. Our results indicate that high strain rates are not a necessary condition to leakages. CO₂ leakage is generally concentrated around regions with high volcanic activity, hydrothermal and geothermal area within zones of extensional regimes such as normal and transtensional strike-slip faulting whereas CH₄ leakage is more commonly associated with oil and gas seeps, mud volcanoes, and other gas vents such as mofettes within zones of transpressional regimes or reverse faulting. Both CO₂ and CH₄ leakages can be present in a few sedimentary basins, generally of extensional origin which experienced reactivation of normal faults.

References

1) Heidbach, . Heidbach, O., Rajabi, M., Cui, X., Fuchs, K., Müller, B., Reinecker, J., Reiter, K., Tingay, M., Wenzel, F., Xie, F., Ziegler, M.O., Zoback, M.L., Zoback, M.D., 2018. The World Stress Map database release 2016: crustal stress pattern across scales Tectonophysics, 744 (2018), pp. 484-498, 10.1016/j.tecto.2018.07.007.

2) Kreemer, C., Blewitt, G., Klein, E.C., 2014. A geodetic plate motion and Global Strain Rate Model Geochem. Geophys. Geosyst., 15 (2014), pp. 3849-3889

How to cite: Levendal, T., Henry, P., Wibberley, C., Gassier, G., and Boisson, M.: A worldwide catalogue of natural CO2 and CH4 surface leakages: An approach on undesirable geological contexts for CO2 storage, taking into account strain rate, stress, and tectonic regime., EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-6151, https://doi.org/10.5194/egusphere-egu22-6151, 2022.

Carbon capture and storage (CCS) gains much attention as it contributes to mitigating climate change. However, during CCS, the periodic injection of pressurized CO₂ leads to strong thermal cycling and shocks in the subsurface, due to the endothermic expansion of pressurized CO₂ upon injection. Under these temperature variations, the wellbore and subsurface formations cyclically contract and expand. As a result, leakage pathways such as micro-annuli between wellbore casing and cement, and cracks in the cement can develop. They impair well integrity, and thus impede safe geological storage of CO₂. Therefore it is of significance to understand how the sealing ability of the cement sheath of CCS wells is affected by thermal cycling or shocks.

In this paper, we report a novel technique to investigate cracking in cement by thermal shocks under in-situ temperature and pressure. To this end, we use a triaxial deformation apparatus capable of mounting a cement sample in a vessel at a confining pressure of up to 70 MPa, with an axial stress up to 26 MPa. An internal furnace is used to achieve an elevated temperature in the vessel. Pore fluid lines are fitted in upper and lower axial pistons to allow water injection. In this study, we use a solid neat cement sample ( Φ30*70 mm, water-to-cement ratio: 0.3) cured at 20ºC and ambient pressure for 28 days. During the experiments, the triaxial vessel is filled with heat-resistant oil which provides the confining pressure. The cement sample is isolated from the oil using a thin Teflon jacket. We load the sample at different in-situ states of hydrostatic stress and heat the sample assembly to various elevated temperatures (60 - 120ºC). We then inject cold water (20ºC) through the sample using two high-pressure syringe pumps at a designated flow rate for a given time. In the vessel, three linear variable differential transducers (LVDT) mounted parallel to, and span around the sample are used to calculate axial and radial strain, respectively. Two thermocouples, one mounted on the middle of the sample (outside the jacket), and another inside the upper pore fluid line, are used to measure temperature. To study how and where cracks initiate and grow in the cement under thermal shocks, we measure permeability with a differential pressure transducer measuring the difference between the up- and down-stream pore fluid line, and we use a micro-computed tomography ( μ-CT) scanner to characterize the microstructure of the cement sample before and after the experiments. This provides valuable expedience to investigate the thermal effects on the integrity of cement under different in-situ conditions for CCS wells. The pistons of the setup can also be readily adjusted to study how de-bonding between casing and cement, and cracks in the cement develop for composite cement samples (with analogous casing) under thermal cycling.

How to cite: Li, K. and Pluymakers, A.: A Novel Technique to Investigate Thermal-Induced Cracking in Cement under In-Situ Conditions for CCS Wells, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-3186, https://doi.org/10.5194/egusphere-egu22-3186, 2022.

Geological storage of carbon dioxide in depleted gas reservoirs or deep saline aquifers is one of the techniques to reduce CO2 in atmosphere and mitigate the greenhouse effects on climate changes.

A Carbon Capture Storage (CCS) plan is composed of different steps (capture, transportation, injection, monitoring just to cite a few) and a comprehensive multidisciplinary investigation must be carried out to define site-specific storage capacity/efficiency, formation injectivity and monitoring, both in short and long terms.

Especially in studying subsurface processes, geological, hydrogeological, petrophysical, mineralogical and geochemical information must be integrated, to evaluate, and possibly predict/quantify, the effects of the dissolution-precipitation processes driven by CO₂injection and the consequent changes in petrophysical properties of the rocks.

In this framework, numerical modelling can play a role of primary importance especially if it can be supported by a complete set of experimental data. To this purpose, a workflow has been recently developed according to the following steps:

• Core description and sample selection, to assure representativeness for the storage complex
• Mineralogical, petrographic, petrophysical, gas and water chemical data acquisition
• Data elaboration and integration to propose a conceptual model
• Numerical simulations
• static models: geochemical validation
• dynamic: CO₂injection and reactive migration

Point 4 is the main focus of this work which aims at describing (i) the near wellbore migration of CO₂and its effects on injectivity, and (ii) the behavior of specific sedimentary lithologies once they have come into contact with CO₂. For this purpose, a sequence of models has been developed, with a growing degree of complexity. 0D pure geochemical models are used to investigate rock reactivity (thermodynamic and kinetic) by taking advantage of the very low computational cost of these models.

The limitations of neglecting mass migration are then overcome by performing 1D cartesian models which are in turn also used to calibrate petrophysical parameters of more CPU-demanding 2D radial models set up for simulating CO₂injection at well scale.

The numerical investigation will be concluded by using a real 3D reservoir model to predict more realistically the dynamics of CO₂migration in the storage complex and its effects on the lithology and petrophysical properties. This last step represents the ideal link/bridge between experimental activity and reservoir models.

All the numerical simulations are carried-out with an Eni-internal software platform (e-muflot, Multiphase Flow and Transport) developed to represent reactive transport in dynamic reservoir models.

How to cite: Beduschi, M. V., Geloni, C., Gherardi, F., Ricci, S., and Toscani, G.: Bridging experimental analysis to reservoir models: a geochemical modelling approach for Carbon Capture Storage, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-2321, https://doi.org/10.5194/egusphere-egu22-2321, 2022.

Carbon Capture and Storage (CCS) sites require microseismic monitoring before, during and after operations to ensure safety of operational personnel and the wider public.

The high dynamic range and low self-noise of broadband seismometers allows for the detection of low magnitude microseismic events which fall below the threshold of less sensitive geophones. Higher long-period sensitivity also allows the full source spectra of earthquakes to be accurately measured, resulting in more accurate magnitude estimations which improve the integrity of any microseismic monitoring system.

Borehole instruments such as the Güralp Radian are a natural fit for detecting low magnitude microseismic events. Optional high gain at the higher frequencies makes the Radian extremely suitable for monitoring low-magnitude induced events while retaining long-period sensitivity for larger ruptures. The slim form factor and omni-angle operation allows the instrument to easily be lowered into decommissioned wells with little information about the orientation at depth.

The Radian is currently being utilised by the British Geological Survey as part of the UK GeoEnergy Test Bed (GTB) to monitor and improve understanding of fluid flow through natural subsurface pathways. A string of 6 interconnected Radians provides vertical profiling around the injection site with a maximum of 8 units able to join in a single string. The Radian will detect and monitor small changes in the subsurface at the GTB as part of the suite of monitoring technologies deployed onsite. 

In addition to onshore networks, offshore depleted gas fields are becoming increasingly scrutinised for potential to store CO2. The advent of Güralp omnidirectional sensor technology combined with acoustic near-real-time data transmission means the Aquarius OBS provides a cost-effective solution for monitoring offshore CCS sites, with infrequent and rapid battery recharging and acoustic data extraction while the unit is still on the seafloor.

How to cite: Cilia, M., Reis, W., Watkiss, N., Mohr, S., Barbara, R., and Hill, P.: Broadband seismic instrumentation for monitoring CCS sites, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-8250, https://doi.org/10.5194/egusphere-egu22-8250, 2022.

This work is conducted within the framework of SUCCEED, a research consortium with the aim to validate the utilization of produced CO₂, from the Hellisheiði geothermal plant in Iceland, for re-injection into the field for: i) pressure maintenance, and thus promoting geothermal production, and ii) permanent storage in basaltic formations through CO₂ mineralisation. The objective of work carried out at Hellisheiði in SUCCEED is to provide a state-of-the-art, cost-effective, and low-environmental impact coupled geothermal-CO₂ storage monitoring technique. In this work, a detailed seismic-velocity and mechanical behaviour-characterisation study was carried out on various rock formations present at the outcrops near the Hellisheiði geothermal site.

Laboratory experiments include well-controlled active-source acoustic-assisted unconfined (UCS) and confined (CCS) compressive strength tests. Where the former, i.e., UCS, allow for investigating the mechanical behaviour, or static elastic properties, of the assessed rock formations, the latter, i.e., CCS, shed light on the seismic velocities at field-representative stress conditions (up to 70 MPa). The abovementioned experiments were conducted at ambient temperature and at dry pore-space conditions. For studying pore-scale phenomena (e.g., number of connected pores, mineralogy, etc.), several thin sections were prepared and micro computed tomography (micro-CT) scans were taken.

The studied rock formations included basalts with varying porosities (ranging from 22 to 51 %), i.e., the main reservoir formation, hyaloclastites, and dykes. Micro-CT scan analyses, conducted on the basaltic reservoir formation in Hellisheiði, revealed that its pore structure is highly heterogeneous. Active-source acoustic-assisted UCS tests showed similar velocity – stress trends: a rapid increase in velocity at low stress levels, related to closure of potential microcracks (and thus compaction), followed by a more modest increase at higher levels of axial stress. The pyroclastic hyaloclastite appeared to be the weakest material assessed, revealing relatively low seismic velocities, a static Young modulus of 2.54±0.09 GPa, and an ultimate strength of around 4.3 MPa. On the contrary, the igneous intrusion, i.e., dyke, is by far the stiffest material studied, yielding a Young modulus of 34.85±0.39 GPa and an ultimate strength of more than 200 MPa. The investigated basalt samples indicated a porosity-dependent Young modulus and compressional-wave velocity, where both the modulus and velocity decrease significantly with increasing (connected) porosity following a power-law function.   

How to cite: Janssen, M., Redondo Garcia, E., Barnhoorn, A., Draganov, D., and Wolf, K.-H.: Storing CO2 in Geothermal Reservoir Rocks: A Laboratory Study on Acoustic and Mechanical Properties, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-4396, https://doi.org/10.5194/egusphere-egu22-4396, 2022.

The focus of this research is a qualitative study of mineralogical and chemical changes in plutonic mafic rock samples after exposure to a CO₂-rich brine, under supercritical conditions (SC), to clarify the behavior of brine and rock in the initial stages of mineral carbonation. The studied rock consists of a gabbro-anorthosite from the Odivelas massif, in southern Portugal. The sample was exposed to a SC CO₂-rich brine (P≈8 MPa, T≈40^◦C) for runs of 0, 30 and 90 days. Experiments were conducted in batch mode, ie. with no CO₂ flow, and with a proportion of CO₂ to brine of 0.226 for 30 days and 0.033 for 90 days. In addition, numerical modeling was applied to complement the experimental observations, reproducing the experimental observations and simulate the chemical behavior for longer times. The chemical analysis of the brine, before and after, the experiment, shows: (i) increase of magnesium (Mg²⁺), calcium (Ca²⁺) and silica (SiO₂) for the 30 and 90 days runs and (ii) decrease of pH (8.1 to 6.1 and 8.1 to 6.3, respectively). Experimental and numerical results indicate that the rock sample suffered a slight dissolution process with mineralogical/textural readjustments on the external area of the specimens studied. This is thought to mimic the initial dissolution process under early-stage mineral carbonation. After 90 days, apart from halite, there are no significant new mineral phases. However, the elemental association in the EDS maps of carbon and magnesium dissociated from silicon suggests the residual crystallization of magnesite.

How to cite: Moita, P., Berrezueta, E., Abdoulghafour, H., Beltrame, M., Mirão, J., Ribeiro, C., Barrulas, P., Pedro, J., and Carneiro, J.: Mineralogical and chemical changes induced by experiments of interaction between supercritical CO2 and plutonic mafic rocks. A case study in Portugal., EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-5158, https://doi.org/10.5194/egusphere-egu22-5158, 2022.

Transitioning towards a carbon managed energy infrastructure is essential to mitigate climate change. Negative emission technologies, such as direct air CO₂ capture (DACC), together with renewable energies will likely to be necessary components in the effort to slow, stop, reverse the flow of carbon dioxide (CO₂) to the atmosphere. The DACC process requires heat and electricity to capture CO₂ from the ambient air, the sources of which may not be climate-benign. We present an approach that combines DACC, long-term CO₂ storage, and geothermal energy production: a climate-benign direct air capture, carbon utilization, and storage (DACCUS). The CO₂ captured from the ambient air, is geologically stored in sedimentary basins, and circulated to the surface in a closed system to extract the available geothermal heat.  The produced heat can be used directly or converted to electricity by a power plant and used in the DACC process.  We investigate the performance of DACCUS systems, including sensitivity analyses of key parameters, such as the sorbent regeneration temperature (80-120°C), the outlet temperature the CO₂ stream from the DACC (70-22°C), and reservoir permeability (1x10^-15-1x10^-11 m²), among others.  The results indicate that DACCUS has a promising potential for using the CO₂ from DACC to produce process energy requirements. For example, with a regeneration temperature of 100°C and a DACC outlet temperature of 70°C, reservoirs with depths equal or above 3.5 km, and geothermal temperature gradients equal or above 35°C/km, can provide sufficient wellhead temperatures. In addition, the maximum DACC capacity for those temperatures increases considerably for reservoir permeability up to 5x10^-14 m², and can provide the make-up CO₂ for that which migrates outside of the region in the aquifer where CO₂ is circulated between the subsurface and the surface. Costs estimates for DACC are $500–600/tCO₂. While also the cost of the integrated system is important, the integration with CO₂-geothermal production could yield substantial savings for DACC ($0.64M - $30.6M annually of avoided electricity costs). 

How to cite: Leveni, M. and Bielicki, J. M.: Climate-Benign Direct Air CO2 Capture, Utilization, and Storage (DACCUS), EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-9795, https://doi.org/10.5194/egusphere-egu22-9795, 2022.

Rapid development of renewable sources (e.g., wind turbines and geothermal energy) has been increasing the market share of renewable energy in electricity production in Ireland with a target of 70% by 2030. However, the production of renewable energy is usually fluctuating, which necessitates the strategies and technologies to match intermittent electricity generation surplus with time-varying market demand. Hydrogen gas generated from surplus renewable electricity has been acknowledged to be a promising energy carrier for balancing this energy gap. In particular, underground hydrogen storage in geological formation emerges as an economically effective and reliable method to store the gas on a large scale. To this end, it is essential to develop a comprehensive understanding of the suitable geological settings for underground hydrogen storage.

This paper investigates various geological settings in Ireland for different types of offshore underground hydrogen storage (e.g., salt caverns, depleted hydrocarbon fields, and aquifers). For each Irish offshore basin, an assessment is conducted to evaluate the potential application of underground storage methods and associated safety & serviceability concerns. The result confirms some prospective areas for different options of hydrogen underground storage at specified conditions. In particular, the offshore sedimentary basins of western and southern Ireland are considered to be suitable UHS geological settings. These shortlisted suitable geological settings deserve further investigation in greater details for the subsequent design & construction of hydrogen underground storage projects.

How to cite: Xiao, Z., Desmond, C., Stafford, P., and Li, Z.: Geological perspectives of offshore underground hydrogen storage in Ireland, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-1645, https://doi.org/10.5194/egusphere-egu22-1645, 2022.

Energy storage is thought to be a crucial part of renewable energy systems as it helps to alleviate the main drawbacks of renewable energy generation: their intermittency and seasonal and geographical constrains. Subsurface storage of hydrogen is one often cited option for geological energy storage and may facilitate the energy transition. Hydrogen can be stored in porous media, such as saline aquifers and depleted hydrocarbon reservoirs, and in engineered salt caverns.

The Upper Rhine Graben (URG) lies within the tri-national Upper Rhine Region where across-boarder decarbonisation scenarios require energy storage infrastructure. Here, we analyse the hydrogen storage potential of sedimentary formations within the URG based on available geological data and models. While the deeply buried sandstones of the Permo-Triassic have generally low permeabilities and porosities and only form fractured reservoirs which have limited suitability for hydrogen storage, Paleogene deposits have some storage potential and host also numerous hydrocarbon reservoirs which may be reutilised. Salt diapirs in the southern URG have the potential to hold many engineered salt caverns with significant storage potential, however the geological knowledge of the internal structure of the salt diapirs is limited. Overall, the potential of geological hydrogen storage within the URG is in the order of several TWh.

How to cite: Miocic, J. and Heinemann, N.: Hydrogen storage potential in the Upper Rhein Graben area, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-5460, https://doi.org/10.5194/egusphere-egu22-5460, 2022.

Zero carbon energy generation from renewable sources can reduce climate change by mitigating carbon emissions. A major challenge of renewable energy generation is the imbalance between supply and demand. To overcome the energy imbalances, subsurface storage of hydrogen in porous mediais suggested as a large-scale and economic solution, yet its mechanisms are not fully understood. Important unknowns are the effect of the high migration potential of the small and mobile hydrogen molecule and the volume of recoverable hydrogen.

We conducted non-steady state, cyclic hydrogen and brine injection experiments at 2-7 MPa and flow rates of 2-80 µl min^-1 using water-wet Clashach sandstone cylinders of 4.7 mm diameter and 53-57 mm length (Clashach composition: ~96 wt.% quartz, 2% K-feldspar, 1% calcite, 1% ankerite). Two sets of experiments were performed using our new transparent flow-cell designed for x-ray computed microtomography: 1) Experiments using a laboratory x-ray source (University of Edinburgh) imaged the flow, displacement and capillary trapping of hydrogen  by brine as a function of saturation after primary drainage and secondary imbibition. 2) Experiments using synchrotron radiation (Diamond Light Source, I12-JEEP tomography beamline) captured time-resolved hydrogen and brine flow and displacement processes. Pressure and mass flow measurements across the experimental apparatus complemented the microtomography volumes in both sets of experiments.

Results from a water-wet rock show that hydrogen behaves as a non-wetting phase and sits in the centre of the pore bodies, while residual brine sits in corners and pore throats. Hydrogen saturation in the pore volume is independent of the injection pressure and increases with increasing hydrogen/brine injection ratio up to ~50% saturation at 100 % hydrogen. Capillary trapping of hydrogen during brine imbibition occurs via snap off and is greatest at higher brine injection pressures, with 10 %, 12% and 21% hydrogen trapped at 2, 5 and 7 MPa, respectively. Higher brine flow rates reduce capillary trapping and increase hydrogen recovery at any given injection pressure. Based on these results, future hydrogen storage operations should inject 100% hydrogen and manage the reservoir pressure to avoid high pressures and minimize capillary trapping of hydrogen during brine reinjection.

Ongoing analysis of time-resolved experimental data will provide further insight into the critical pore-scale processes that ultimately influence the potential for geological hydrogen storage and recovery.

How to cite: Thaysen, E. M., Butler, I. B., Freitas, D., Hassanpouryouzband, A., Alvarez-Borges, F., Atwood, R., Humphreys, B., and Edlmann, K.: Hydrogen recovery from porous media decreases with brine injection pressure and increases with brine flow rate   , EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-2458, https://doi.org/10.5194/egusphere-egu22-2458, 2022.

In alignment with the Paris Agreement, more than 120 countries have now committed to reaching net zero by mid-century. Among the future energy storage technologies required for limiting global warming to well below 2 °C, geological storage of hydrogen is considered as a strong candidate to support increased renewable electrification. It is therefore crucial to understand the impact of injected hydrogen on geochemical equilibrium in these geological storage settings. Here, we investigate the potential for hydrogen reactions with different pure minerals using our custom high pressure/temperature batch reactors. Minerals examined include Gypsum, Calcite, Dolomite, and two types of Pyrite. We conducted the experiments at high pressure and temperature conditions with simulated reservoir brine, representing real geological conditions. Moreover, we conducted control experiments with inert nitrogen to ensure confidence that any identified geochemical reactions are induced by hydrogen, rather than elevated, temperature, pressure or brine chemistry. Our results suggest that abiotic geochemical reactions are not likely to result in hydrogen loss within the time scales of geological hydrogen storage.

How to cite: Hassanpouryouzband, A., Thaysen, E. M., Wilkinson, M., and Edlmann, K.: The Geochemistry of Pure Minerals with Pure Hydrogen in Aqueous Solutions, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-6162, https://doi.org/10.5194/egusphere-egu22-6162, 2022.

As the integration of wind and solar energy increases, so does the need for large-volume and efficient storage to balance fluctuations in power generation and demand.

In order to meet this demand, the proportional injection of renewable hydrogen into the natural gas grid or directly into underground storage facilities (UGS) is already being investigated in several pilot studies. Large-scale hydrogen storage, especially in salt caverns, is considered to have great potential in the context of carbon-free energy supply. From microbiological studies of numerous cavern and porous storage facilities, it is known that most UGS are already colonized with microorganisms that can use hydrogen as their sole energy source.

The results of several research projects and analyses of numerous underground storage facilities with regard to the stimulation potential of existing microorganisms give clear indications of associated risks. The results of these studies also contradict the widespread assumption that saturated brine in caverns generally provides sufficient protection against microbial colonization.

Long-term analyses with over 70 active cultures enriched from different underground storage and reservoir samples and tests with original formation waters show significant hydrogen consumption even in saturated brine with simultaneous H₂S formation by SRB. Carbonates from the minerals of the rock matrix can be used as a necessary carbon source. For a practical simulation of hydrogen storage, in addition to microcosm experiments, numerous high-pressure tests were carried out at storage-relevant conditions over several months with original brine and core samples from different storage types. In some cases, considerable hydrogen conversions and sulfide formation rates were found.

In addition to the influence of hydrogen injection on microorganisms in storage facilities, two projects are also investigating dedicated biological methanogenesis in 11 porous UGS. Presence of microorganisms was detected in almost all reservoirs. Active methanogenic archaea were enriched from three facilities and their ability for methanogenesis was studied and confirmed under different conditions (pressure, temperature, salinity). However, microorganisms with competing metabolic pathways were also detected (e.g. sulfate reducers and acetogens).

The presentation summarizes the results of microbiological investigations on storage and reservoir samples from more than 10 years and gives an overview of relevant microbial processes and their potential impact on technical operations.

How to cite: Wagner, M., Nowack, G., Pretzien, T., and Krasper, L.: Microbiological impacts of hydrogen injection into underground storages, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-12726, https://doi.org/10.5194/egusphere-egu22-12726, 2022.

Utility-scale hydrogen storage will be essential in the UK for meeting carbon emission goals[1]. It is estimated that approximately 150TWh of seasonal energy storage is necessary to negate seasonal variations in natural gas production[2]. This capacity can be easily met through compression and storage of hydrogen within depleted gas reservoirs and deep saline aquifers[2]. However, there are several limitations to porous storage, such as the mixed composition of the produced fluid, higher cushion gas requirements, slower release kinetics and longer storage cycles.

Due to the storage dynamics of salt caverns, single gasses can be stored with minimal mixing, allowing for reduced post-storage processing and higher deliverability. This provides caverns with an essential role in both seasonal and daily load management as well as providing a source of energy for high purity hydrogen applications (i.e. transport and fuel cells). The national grid estimates 51TWh of cavern storage will be necessary by 2050[3].

Although new caverns will be necessary, there are several benefits to repurposing current facilities:

• Above ground infrastructure is already available
• Freshwater savings, approximately 7-8m³ per m³ cavern size[4]
• Shorter lead times on storage development
• The reduced expense for geological exploration

Current methods for repurposing suggest the reflooding of the cavern with high salinity brine to replace the gas within, brine production and hydrogen injection then follows this; a process estimated to take 3-7 years. Although less time than for new developments, the risk of unacceptable leakage and the still considerable cost acts as barriers to its implementation.

Our research aims to provide the first investigation into repurposing through gas replacement, determining the number of cycles necessary before an acceptable purity can be attained. This will be simulated with GPSFLOW (General Purpose Subsurface Flow simulator), a software capable of modelling multiphase-multicomponent storage within salt caverns, deep saline aquifers and depleted gas fields[5]. The geological model utilised will be an idealised version of the Stublach cavern in Cheshire, England.

Two approaches are proposed, the first being an injection cycle of high purity hydrogen and the monitoring of hydrogen quality in the produced fluid as the number of cycles increases. Alternatively, the use of CO₂ as means to replace the CH₄ and then the subsequent hydrogen injection cycles will be simulated. The significance of this work is to provide an initial insight into repurposing through gas replacement which, if functional, may provide a reduced transitionary period and considerable resource savings.

References

• Wallace, R.L., Z.S. Cai, H.X. Zhang, K.N. Zhang, and C.B. Guo, Utility-scale subsurface hydrogen storage: UK perspectives and technology. International Journal of Hydrogen Energy, 2021. 46(49): p. 25137-25159.
• Scafidi, J., M. Wilkinson, S.M.V. Gilfillan, N. Heinemann, and R.S. Haszeldine, A quantitative assessment of the hydrogen storage capacity of the UK continental shelf. International Journal of Hydrogen Energy, 2021. 46(12): p. 8629-8639.
• National Grid, Future Energy Scenarios. 2021.
• Warren, J.K., Solution Mining and Salt Cavern Usage, in Evaporites: A Geological Compendium, J.K. Warren, Editor. 2016, Springer International Publishing: Cham. p. 1303-1374.
• Cai, Z., K. Zhang, and C. Guo, Development of a Novel Simulator for Modelling Underground Hydrogen and Gas Mixture Storage. International Journal of Hydrogen Energy, 2021.

How to cite: Wallace, R. and Cai, Z.: Numerical Assessments of Repurposing a Natural Gas Cavern for Hydrogen Storage, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-6644, https://doi.org/10.5194/egusphere-egu22-6644, 2022.

Underground hydrogen storage can store grid-scale energy for balancing both short-term and long-term inter-seasonal supply and demand. However, there is no numerical simulator which is dedicated to the design and optimisation of such energy storage technology at grid scale. This study develops novel simulation capabilities for GPSFLOW (General Purpose Subsurface Flow Simulator) for modelling grid-scale hydrogen and gas mixture (e.g., H₂-CO₂-CH₄-N₂) storage in cavern, deep saline aquifers and depleted gas fields.

The accuracy of GPSFLOW is verified by comparisons against the National Institute of Standard and Technology (NIST) online thermophysical database and reported lab experiments, over a range of temperatures from 20-200 ^oC and pressure up to 1000 bar. The simulator is benchmarked against an existing model for modelling pure H₂ storage in a synthetic aquifer. Several underground hydrogen storage scenarios including H₂ storage in a synthetic salt cavern, H₂ injection into a CH₄-saturated aquifer experiment, and hydrogen storage in a depleted gas field using CO₂ as a cushion gas are used to test the GPSFLOW’s modelling capability. The results show that GPSFLOW offers a robust numerical tool to model underground hydrogen storage and gas mixture at grid scale on multiple parallel computing platforms.

How to cite: Cai, Z., Zhang, K., and Guo, C.: GPSFLOW: A Novel Simulator for Modelling Underground Hydrogen, CO2 and Gas Mixture Storage, EGU General Assembly 2022, Vienna, Austria, 23–27 May 2022, EGU22-3064, https://doi.org/10.5194/egusphere-egu22-3064, 2022.